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TABLE OF CONTENTS

CHAPTER 2 APPLICABILITY ................................................................................................. 2

2.1 Overlap of Sections 111(b) and 111(d)............................................................................ 3

2.2 Proposed Applicability vs. Broad Applicability........................................................... 18

2.3 Applicability issues related to EGUs that fire biomass or other non-fossil fuels...... 32

2.4 Applicability issues related to combined heat and power (CHP)............................... 36

2.5 Definition of Affected Source......................................................................................... 54

2.6 Comments regarding subcategorization....................................................................... 66

2.7 Other ................................................................................................................................ 76
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CHAPTER 2 APPLICABILITY

This chapter addresses public comments on the applicability provisions of the EPA's CAA 

section 111(d) guidelines for establishing standards for carbon emissions from existing EGUs as 

proposed on June 18, 2014 under 40 CFR part 60 subpart UUUU. Consistent with paragraph 

111(d) (1) (A) of the Act, the applicability guidelines for existing EGUs largely reflect the 

applicability provisions established under the New Source Performance Standards for EGUs 

promulgated at 40 CFR part 60 subpart TTTT with one exception for simple cycle combustion 

turbines based on other factors, as allowed by paragraph 111(d) (1) (B) of the Act. This chapter 

addresses comments on the following categories, design criteria, and operating criteria that 

comprise the applicability provisions of the guidelines:

• Overlap of section 111(b) and 111(d);

• Broad applicability approach;

• Applicability issues related to EGUs that fire biomass or other non-fossil fuels;

• Applicability issues related to combined heat and power units;

• Definition of affected source;

• Subcategorization

• Other.

Commenters also raised issues on topics that are not covered by this chapter. Please refer to the 

following chapters for responses specific to those issues:

• Chapter 1: Legal

• Chapter 3: GHG Mitigation Measures

• Chapter 4: State Goal Computation

• Chapter 5: State Plan Considerations

• Chapter 6: State Plans

• Chapter 7: Interactions With Other EPA Programs and Rules

• Chapter 8: Impacts and Cost Analysis

• Chapter 9: Statutory and Executive Orders
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• Chapter 10: Rule Language Corrections

2.1 OVERLAP OF SECTIONS 111(B) AND 111(D)

This section addresses comments received on interactions of the EGU GHG Emission Guidelines 

with the EGU GHG NSPS regarding new, modified, or reconstructed sources.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Section 111(b) applicability must be promulgated first, and the applicability 

criteria under sections 111(b) and (d) must be the same for new and existing sources. There were 

differences in the proposal preamble and rule text discussions that must be clarified.

Response 1: The 111(b) applicability includes all units (assuming they are new) that are 

included in the 111(d) applicability. See section IV.C of the final rule preamble of the CPP for 

discussion of the applicability relationship between sections 111(b) and (d) of the CAA. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the concurrent rulemaking efforts undermine the goal of ensuring the 

owners or operators of an existing source have clear notice of and a chance to prepare for the 

application of a new regulatory scheme. Commenters stated that EPA's reliance on regulations 

that are not finalized also compromises stakeholders' opportunity to comment on the proposed 

rule; because the section 111(b) rule for new sources has not been finalized, stakeholders cannot 

know with certainty which existing units will be affected by the section 111(d) proposal. 

Commenters stated this has been a particular challenge for Alaska. Commenters stated that, for 

example, EPA proposes different applicability criteria for existing and new steam generating 

units: a new steam generating unit would be covered by the 111(b) rule only if it was constructed 

for the purpose of supplying, and supplies a threshold amount of electric output; by comparison, 

and contrary to the intent articulated in the preamble, the proposed section 111 (d) rule omits the 

"and supplies" from the applicability criteria for existing EGUs. Commenters stated that if this 

disjuncture persists, EPA would be seeking to regulate existing sources under section 111(d) that 

would not be regulated as new sources under section 111(b).

Commenters stated that without a final 111(b) rule, they cannot evaluate whether one of their 

coal units will be an "affected EGU;" this information is critical to understanding the possible 

impact of the rule in Alaska for evaluating what concerns should be raised in their section 111(d) 

comments.

Commenters believed that paragraph 111(d) (1) (A) (ii) requires that the Agency must first 

propose a section 111(b) standard for all sources that meet the definition of "new source" under 

paragraph 111(a) (2) to establish both the operative date necessary for differentiating new 
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sources from existing sources and the congruent scopes of applicability under paragraphs 111(b) 

and paragraph 111(d).

Commenters stated that the proposed applicability criteria for existing EGUs are unlawful 

because the proposed definition of "affected EGU" is broader in the rule proposed under section 

111(d) authority than the proposed definition of affected EGU in the rule proposed under section 

111(b) authority, and commenters believed that the applicability provisions for existing sources 

improperly include EGUs that qualify for exemption based on the proposed NSPS thresholds for 

use of fossil fuels and electricity sales. Commenters stated that the definition of "affected EGU" 

in the proposed guidelines must retain the exclusions for new subpart Da units proposed in 

January of 2014 (i.e., the "low fossil use criterion" and the "one-third sales criterion") because 

the preamble to the proposed guidelines invoked the NSPS applicability (79 FR 34854) and 

commenters did not believe that the EPA provided any legal or technical rationale for altering 

the scope of what Subpart Da units qualify as "affected EGUs" in the proposal for existing 

sources. Commenters cited CAA section 307(d) as requiring the Agency to provide a technical 

rationale for increasing the scope of sources subject to the 111(d) standard as compared to the 

scope of sources proposed for the NSPS, and commenters stated that if EPA adopts final 

emission guidelines, it should define "affected EGUs" to be consistent with the definitions in the 

January 2014 NSPS Proposal. Commenters believed that the applicability criteria proposed in the 

January 8, 2014 proposal is preferable to the applicability proposed under the section 111(d) 

guideline because they believed that a criteria based on actually supplying more than 219,000 

MWh net is appropriate, in order to bring only the truly large units under the Rule.

Commenters believed that the Agency cannot lawfully finalize guidelines under section 111(d) 

without first re-proposing the 111(b) standards for new sources with applicability criteria that are 

consistent across both the 111(b) and 111(d) proposals. Commenters stated that section 111(d) 

and 40 CFR 60.22 require the Agency to propose section 111(b) standards for the same types of 

sources included in subsequent proposals under section 111(d). Similarly, commenters believed

that section 111(d) and 40 CFR 60.22 establish a prerequisite for the Agency to finalize section 

111(b) standards for new sources prior to promulgating 111(d) standards for existing sources 

with identical applicability criteria.

Commenters stated that the proposed approach for using "Broad Applicability" criteria to apply 

no emission standard to a set of new sources under section 111(b) authority in order to increase 

the scope of existing sources that could be included in a standard issued under section 111(d) 

authority will not affect the scope of what existing EGUs may be eligible for regulation under 

section 111(d) because under section 111(d), a state plan may establish standards of performance 

only for "any existing source . . . to which a standard of performance under [section 111] would 

apply if such existing source were a new source." Commenters believed that "no emission 

standard" is not a "standard of performance" as defined in section 111(a) (1) because a 

"standard of performance" is defined as a "requirement of continuous emission reduction."

Commenters stated that applicability under section 111(d) regulations should be clear and 

consistent with applicability provisions under section 111(b) regulations, and commenters

opposed the differences included in the 111(d) proposal. Commenters stated that the various 

applicability provisions included in the three proposals issued under section 111 authority were 

ambiguous and confusing, and commenters found it difficult to determine which sources should 
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be included for capital and compliance planning by operators and states. Commenters stated that 

portions of the preamble stated that the rationale for applicability under 111(d) was the same as 

the rationale for new sources under section 111(b), but that the regulatory texts differed, and 

commenters stated that the proposal included no justification or rationale for the 

differences. Commenters stated that the proposed 111(d) rule was inconsistent and unclear 

regarding in the definition of an affected EGU. Commenters agreed with the scope of 

applicability presented in section V.C of the section 111(d) preamble because this portion of the 

proposal described applicability of the 111(d) proposal consistently with the January 8, 2014 

proposal under 111(b) as required by section 111(d) (1) (A) (ii). However, commenters opposed

the proposed regulatory text at section 60.5795(b)(1) because this paragraph deviated from the 

January 8, 2014 applicability criteria, and commenters believed that the proposed section 111(d) 

applicability criteria could be interpreted to mean that a biomass unit that only uses fossil fuel for 

startups is an affected EGU under section 111(d), and commenters provided draft language for 

section 60.5795(b) that would ensure consistency between the section 111(b) proposed 

regulatory text, the section 111(d) regulatory text and Agency intentions stated in section V.C of 

the 111(d) proposal. 

Commenters urged the EPA to correct inconsistencies across the three section 111 proposals.

Commenters believed that the differences in applicability under the section 111(b) and section 

111(d) proposals for steam generating units and IGCC units were drafting errors and commenters

requested that the final rule correct these drafting errors.

Commenters opposed the differences in the applicability criteria proposed for the section 111(d) 

as compared to the applicability criteria proposed for the section 111(b) rules, because 

commenters believed that the statute requires the EPA to use the same applicability criteria for 

the 111(d) rule that is established in the precedent 111(b) rules. 

Commenters specifically opposed the applicability criteria for Subpart Da units under the section 

111(d) proposal because these applicability criteria are inconsistent with the applicability criteria 

proposed for new sources under section 111(b) authority. Commenters believed that the statutory 

language under section 111(d) includes a restriction that the regulated entity must be identical in 

the section 111(b) and section 111(d) regulations.

Commenters believed that changing the applicability criteria in the section 111(d) proposal also 

appears to change the applicability criteria of 111(b) regulations.

Commenter stated, the EPA proposes changes to applicability requirements and emission 

standards would have implications for both new and existing requirements.

Commenters requested that the EPA withdraw the section 111(d) proposal because commenters

believed the prerequisite standards for new sources under section 111(b) did not constitute an 

NSPS as defined in section 111, and commenters believed that subsequent standards under 

111(d) must have applicability criteria substantively identical to the criteria for new sources. 

Commenters believed that the proposed applicability criteria for new sources are inconsistent 

with the definition of "standard of performance" in section 111(a) because the proposed standard 

for emissions of CO2 to the atmosphere does not apply to all components of the carbon capture 
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and sequestration technology determined by the EPA to be the best system of emission reduction 

(BSER). Commenters acknowledged that the proposed applicability criteria encompasses 

stationary source operations through capture of the CO2 produced from fossil-fuel combustion at 

the stationary source, but commenters believed that disposition of the captured CO2 after it 

leaves the stationary source is outside the scope of the proposed NSPS; commenters referred to 

omission of BSER components (with the potential to emit captured CO2 to the atmosphere) as a 

"fatal flaw" in the proposed applicability criteria for these section 111 standards.

Commenters stated that the EPA has no authority to require the installation of equipment that is 

not within the scope of a "steam generating unit" because existing unit standards of performance 

under section 111(d) can only apply if the existing source were a new source, and the scope of a 

"steam generating unit" must be examined by referring to the standard for new sources under 

subpart Da. Commenters asserted that subpart Da limits the scope of a steam generating unit to 

"any furnace, boiler, or other device used for combusting fuel for the purpose of producing 

steam..." Commenters believed that this means that other equipment such as steam turbines 

cannot directly or indirectly be considered when establishing BSER or a standard of 

performance. Commenters cited support for their position from a November 25, 1986 EPA 

memorandum entitled, Interpretation of Reconstruction; the memorandum details what items of 

equipment are included in the scope of a new steam generating unit, and the memorandum 

includes a diagram clearly showing the scope of a steam generating unit. Commenters opposed

the proposal's reliance on efficiency improvement projects that pertain to steam turbines because 

the diagram in the November 25, 1986 EPA memorandum does not encompass the steam 

turbine. Commenters also stated that EPA has improperly included many systems (or facilities) 

at EGUs that are not defined by the 1986 EPA memo as part of the affected source. Commenters

believed that the proposal's reliance on these out-of-scope facilities in the building block one 

analysis is inappropriate because the Act requires that section 111(d) standards must apply only 

to a source "to which a standard of performance under this section would apply if such existing 

source were a new source."

Commenters stated that the final rule should resolve inconsistencies in the definition of affected 

source between the definition of "affected source" in the preamble of the proposed rule and the 

definition of "affected source" in the proposed rule text because the definition of "affected 

source" in the preamble includes the criteria that an EGU combust fossil fuel for more than 10 

percent of its total annual heat output, but proposed section 60.5795(b)(1) does not include this 

criteria for steam generating units. Commenters stated that this inconsistency has 

generated confusion among RGGI states because the list of affected sources used to set 

individual state goals is inconsistent with the proposed definition. Commenters stated that if the 

proposed definition is included in the final rule, the list of affected sources will need to be 

broadened and the state goals must be amended accordingly. Commenters stated that this 

uncertainty made it challenging for affected states to submit complete and accurate 

comments. Commenters stated that to remain consistent with the intent of the preamble, the rules 

proposed for new, modified, and reconstructed sources under 111(b) and the definition of 

"affected source" as applied in the setting of state goals, the EPA should amend the definition of 

"affected source" in section 60.5795(b) (1) to include the 10 percent fossil fuel requirement for 

steam generating units.
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Commenters stated that the final rule should correct inconsistencies in the definition of affected 

source because the definition of affected source in the preamble to the proposed rule is different 

from the definition of affected source in the proposed rule text. Commenters stated that the 

definition of affected source in the preamble includes the criteria that an EGU combust fossil 

fuel for more than 10 percent of its total annual heat output, but proposed section 60.5795(b) (l) 

does not include this criteria for steam generating units. Commenters stated that this provision 

was critical to an EGU operating in his state and requested that the final rule definition include 

this 10 percent criteria.

Comment 2: Support and opposition for dual applicability under sections 111(b) and 111(d).

Response 2: The EPA agrees with commenters that 111(d) applicability should not include 

111(b) units and the definition of affected unit in 111(d) final rule does not include 111(b) units.

The following are summaries of the specific public comments under this comment:

Commenters stated that the only major departure would be the dual applicability of 111(b) new 

source and 111(d) existing source standards, and commenters recognized the legal intricacies of 

that distinction. Commenters stated that there are ways to accommodate this through appropriate 

definitions, opt-in provisions, or other creative means.

Commenters stated that the proposal's reinterpretation of Section 111(d) is at odds with the Act, 

prior rulemakings, and prior interpretations because in the past sources subject to standards under 

section 111(b) were not also subject to standards under 111(d).

Commenters stated that the proposed compliance options under the section 111(d) proposed rule 

are unclear and requested that the EPA clarify and justify how power generation facilities 

permitted under its proposed carbon dioxide emission rule for new power plants would be treated 

for purposes of complying with its proposed rule for existing power plants.

Commenters stated that EPA should not require emissions from a 111(b)-regulated facility to 

count against an emission limit (rate or mass-based) for 111(d) covered facilities as the two 

categories are mutually exclusive; a facility cannot be regulated under both statutory provisions. 

However, commenters stated the broad flexible construct EPA has conceived for this proposed 

111 (d) rule provides no logical impediment to providing states the options to (a) use the 

emission rates of 111(b) facilities to average down or take the place of emissions from existing 

111(d) covered facilities; or (b) count 111(b) emission reductions over-compliance toward 

emission reductions required by a mass-based State plan.

Commenters stated that they disagree with EPA position that there is sufficient ambiguity in the 

CAA to allow EPA to require inclusion of these section 111(b) sources in a section 111(d) plan. 

Commenters stated that the CAA is clear that a modified source is treated as a new source, and 

that a new source is not an existing source. Commenters stated that clearly, an existing source is 

separate from a new source, and section 111(d) only applies to existing sources. Commenters
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requested that EPA regulate new sources solely under section 111(b) and existing sources solely 

under section 111(d).

Commenters stated that when establishing state goals, the Agency must exclude sources that do 

not meet the applicability criteria proposed for new sources. Commenters stated that for steam 

generating units and IGCC units, the 111(d) proposal eliminated proposed 111(b) applicability 

thresholds based on use of fossil fuels and electricity sales; commenters opposed elimination of 

these applicability criteria in the 111(d) proposal. Commenters stated that these proposed 

differences in 111(b) and 111(d) applicability criteria resulted in the erroneous inclusion of 

certain EGUs when establishing the proposed goal for the State of Florida. Commenters stated

that certain units that do not meet the proposed applicability criteria under the proposed section 

111(b) applicability criteria should not have been included by the Agency when calculating the 

proposed section 111(d) goal for the State of Florida.

Commenters stated that inconsistencies between the applicability criteria proposed for new 

sources and the applicability criteria proposed for existing sources resulted in inclusion of EGUs 

in calculation of the proposed goal for the State of Florida that, if new, would not be subject to 

the section 111(b) standard for new sources; commenters believed that inclusion of these units is 

inconsistent with the requirements of paragraph 111(d) (1) (A) (ii). Commenters stated that the 

Agency erroneously included in the proposed goal for the State of Florida EGUs with federally 

enforceable permit limits that fall below proposed 111(b) applicability thresholds, and 

commenters provided a listing of these units with a request that the Agency remove these EGUs 

from future goal calculations.

Commenters stated that the EPA has historically made a distinction between existing sources and 

new sources in its rule making. Commenters said it is unclear why the EPA is attempting to 

regulate an existing source by both sections 111(b) and 111(d) of the Clean Air Act. Commenters 

said this essentially imposes a limit on a unit twice. Commenters suggested that the EPA should 

remain consistent with how it has issued regulations in the past.

Comment 3: Support and opposition for modified and reconstructed sources to remain as 

section 111(d) existing sources.

Response 3: The EPA agrees with commenters that 111(d) applicability should not include 

111(b) units and the definition of affected unit in 111(d) final rule does not include 111(b) units.

See section VIII.D of the final rule preamble of the CPP for the EPA’s response to existing 

sources that undergo a modification. 

The following are summaries of the specific public comments under this comment:

Commenters found as problematic EPA's proposal that would result in modified and 

reconstructed sources also being subject to standards for existing sources; dual regulation.
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Commenters stated that the EPA provides no legal basis for requiring existing sources subject to 

section 111(d) to continue to be regulated under state plans under section 111(d), post 

modification or reconstruction, in addition to being subject to requirements under section 111(b). 

The commenters also stated that the EPA's proposal does not explain what is meant by the phrase 

"subject to a state plan under section 111(d)," and the draft rule language in the technical support 

documents does not provide clarity on this issue or the dual applicability of section 111(b) and 

section 111(d). The commenters stated that the proposed rule does not explain how this concept 

integrates with current regulatory text in 40 CFR section 60.14 and section 60.15 specifying that 

modified and reconstructed facilities become "affected facilities" if certain criteria are met. 

Commenters stated the EPA is proposing a "once in always in" rationale for units subject to 

section 111(d), which is contrary to the statute and to past section 111(d) actions. The 

commenters stated that, ironically, the EPA says in its proposal, that it should be noted at the 

outset that the EPA determined that reconstructions are a type of construction, and therefore 

subject to CAA Section 111(b), as part of the 1975 framework regulations, and the EPA is not 

re-opening that determination (79 FR 34981); yet, the EPA has taken the contradictory position 

that sources that are modified or reconstructed remain regulated under section 111(d). The 

commenters stated that if Congress intended modified sources to remain under section 111(d), 

then there would have been no need to define "modification" in section 111(a) and set standards 

for modified sources in section 111(b), since modified sources are just existing sources that have 

undergone a physical change. The commenters stated that the EPA's departure from applying 

BSER to the emission source in formulating state goals under section 111(d) results in 

significantly different performance standards for modified or reconstructed sources compared to 

state goals, along with the impossibility of demonstrating compliance with the goals in state 

plans; for example, the EPA would not be able to assume existing turbines to be re-dispatched up 

to 70 percent under Block 2 for the purposes of setting state goals under the proposed section 

111(d) rule if these units ceased to be subject to section 111(d) upon reconstruction or 

modification. The commenters stated that, similarly, all existing coal-fired EGUs could 

potentially be considered modified, depending upon the physical changes each unit implements 

to achieve Block 1 six percent heat rate improvement, thereby removing them from regulation 

under state plans formulated under section 111(d) and the fact that the EPA has proposed a 

schema for existing sources under this proposed section 111(d) rule that is dependent on a 

captive source population is not a rational basis for deviating from the plan language of the 

FCAA and established precedent regarding modification or reconstruction of sources subject to a 

section 111(d) state plan. The commenters stated that because the EPA has provided no rational 

basis to support this position, the EPA should withdraw its proposal regarding dual applicability 

under section 111 and modify proposed section 60.5795 to exclude modified or reconstructed 

sources consistent with prior section 111(d) rules.

Commenters stated that EPA should not attempt to regulate CO2 emissions for the same source 

under both section 111(b) and section 111(d) of the CAA. The commenters stated that 

considering how modified and reconstructed sources may already be drawn from the group of 

existing units that EPA has proposed to regulate for CO2 emissions under Section 111(d), they 

recommended that EPA simply exempt modified and reconstructed sources from CAA Section 

111(b) regulation. The commenters said that states should retain the flexibility to exempt or 

assign regulatory applicability to modified and reconstructed sources for CO2 emissions and, if 

necessary, these state-driven, flexible assignments could be proposed by the states in their 111(d) 

State Implementation Plans. The commenters stated that new NGCC or coal generating units 
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regulated under Section 111(b) and subject to CO2 New Source Performance Standard 

requirements should not also be subject to regulation under Section 111(d) existing unit 

requirements.

Commenters stated that the 111(b) proposal for modified and reconstructed sources is in conflict 

with the Agency's 111(d) proposed guidelines. The commenters stated that generally, the 

strictness of the NSPS progresses with the strictest limit reserved for wholly new facilities; the 

next and lesser strict standard applies to reconstructed units; the next level of standard applies to 

those units that are modified to increase net emissions above significance thresholds; and the 

least strict standards are applied to existing units that continue to operate as designed, and, for 

which, the burden of installing new designs and controls to achieve lower emissions is the 

hardest to justify. The commenters stated that this is how the EPA has historically applied NSPS 

and new source review to emitting sources; but the EPA now turns that program on its head, 

most evident when comparing the proposed requirements under 111(b) and the proposed 

guidelines under 111(d). The commenters stated that where one would expect to see the most 

stringent limits on brand new, yet-to-be-constructed sources, in fact the lowest, most stringent 

limits are proposed for existing units under 111(d), where existing utility boilers in states such as 

North Carolina or South Carolina will have to meet emission rates of 992 and 772 pounds per net 

megawatt hour of CO2, respectively, whereas, utility boilers yet to be constructed must meet a 

rate of 1,110 lbs./MWh-net of CO2, and that with carbon capture and sequestration, while 

modified or reconstructed units would have to meet a maximum emission rate of 1,900 

lbs./MWh-net of CO2.

Commenters, stated in its 111(b) proposal the EPA states that rebuilding with the most efficient 

technology should be BSER for an affected unit (and yet it proposes an emission rate of 1,900 

lbs. /MWh-net), and admits that even smaller emission reductions are the best that can be hoped 

for with best operating practices and equipment upgrades; yet the least stringent emission rate 

proposed by the EPA under 111(d) is less than 1,800/MWh-net. The commenters stated even 

more telling is that modified or reconstructed units would have to achieve efficiency 

improvements of 2 percent, while an existing utility boiler making no change would have to 

achieve an initial 6 percent improvement, as proposed by EPA in Block 1 of the agency's 

preferred option. The commenters stated that the EPA offers no reliable data to support the 

achievability of either a 2 percent or 6 percent improvement and provides no information 

regarding the durability of such an improvement and noted that many efficiency improvement 

measures begin to degrade as soon as they become operational; thus, CO2 reductions from 

efficiency improvement projects are real, but fleeting and cannot be counted on to provide 

lasting reductions.

Commenters stated that the EPA states in its 111(b) proposal that the most improvement an 

existing utility boiler can reasonably make is a 2 percent improvement, thereby undercutting the 

justification in its section 111(d) proposal for an initial 6 percent improvement for existing utility 

boilers.

Commenters stated that another puzzling part of the EPA's proposal is that a boiler may be 

subject to both 111(d) and 111(b). The commenters stated that under any other NSPS, a modified 

source would be required to meet a standard equal to or more stringent than an existing source, 

so no question arises about whether an existing source affected under NSPS guidelines must 
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continue meeting those guidelines once it triggers section 111(b) as a modified source. The 

commenters continued that, however, by establishing a more stringent standard for covered 

existing units, the EPA must develop some rationale for continuing to subject an existing unit to

the more stringent existing source standard even when it modifies the unit and triggers 

application of the lesser 111(b) standard. The commenters stated that all of these regulatory 

contortions are avoided if the EPA proposed a reasonable 111(d) standard. Commenters stated in 

effect, the EPA proposes two different best systems of emission reduction standards and attempts 

to apply them simultaneously to the same unit; thus, this part of the proposal is arbitrary, 

capricious, and exceeds the legal limits of the EPA's authority.

Commenters stated that the EPA cites K Mart Corp. v. Cartier, Inc., to support its approach of 

creating two separate systems of BSER and applying them to the same units simultaneously; 

however, K Mart is not a CAA case, and the fact that the best authority the EPA could find to 

justify its proposal is an unrelated case about trademarks and gray goods is an indication that this 

proposal is unprecedented and that the EPA has overstepped the bounds of its authority.

Commenters stated that EPA's assertion that they can regulate existing sources that modify or 

reconstruct under both the existing source and new source provisions of section 111 because 

section 111 is silent on whether requirements imposed under a 111(d) plan continue for a source 

that ceases to be an existing source because it modifies or reconstructs is incorrect. The 

commenters stated that 111 (a) definitions of new and existing sources are mutually exclusive 

and that once a modification or reconstruction commences, the existing source ceases to exist 

and a new source emerges; and, new sources are subject to regulation pursuant to 111(b) and 

111(d) cannot apply to sources subject to section 111(b). Commenters stated the two policy 

reasons EPA sets forth to justify its proposed decision to subject new sources to both existing 

and new source regulatory requirements (see 79 FR 34904) would be resolved by withdrawing 

the proposed standards for modified and reconstructed EGUs; the EPA has discretion not to 

impose NSPS for modified or reconstructed units and by choosing not to do so in this instance, it 

would avoid the concerns it has raised. The commenters stated that State plans devised with the 

correct statutory interpretation in mind can include provisions to accommodate such changes; 

indeed, the EPA envisions many sources shutting down as a result of the proposed guidelines 

and, if state plans can accommodate units leaving the program through cessation of operations, 

there is no reason why they cannot accommodate the transition of modified or reconstructed 

units from the existing source program to the section 111(b) program for new sources. The 

commenters stated that in addition, to the extent the EPA has designed a section 111(d) program 

that cannot function while adhering to the requirements of section 111(a)(2) and section 

111(a)(6), it is the EPA's proposal, not the CAA, that must be revised.

Commenters stated that with regard to the EPA's concern that there could be an incentive for 

sources to modify or reconstruct to avoid their obligation under a CAA section 111(d) plan, for 

the reasons explained above, a source that undertakes a modification or undergoes reconstruction 

after the date of the proposal of the applicable NSPS has no obligation under a section 111(d) 

plan; it could only have such obligation as a matter of state law at the state's discretion. The 

commenters stated that EPA cannot require states to regulate a unit as both a new and existing 

source. 
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Commenters disagreed with EPA's proposal to require existing EGUs to remain subject to state 

or federal section 111(d) plans even after they undergo a modification or reconstruction that 

triggers CO2 NSPS regulation under section 111(b); this is not necessary to achieve EPA's CO2 

emission reduction goals, and is contrary to the plain text of section 111. The commenters stated 

that as a matter of environmental policy, EPA should not discourage existing units from 

investing in modifications and reconstructions that result in reduced emission rates for pollutants, 

including CO2, and are also an important source of jobs. The commenters stated that units 

contemplating modification or reconstruction in the future may be discouraged by the prospect 

that they would need to meet both state section 111(d) plan requirements and federal standards of 

performance for modified sources. The commenters stated that EPA should clarify that modified 

and reconstructed units will cease to be subject to any section 111(d) plan to which they were 

previously subject upon the commencement of modification or reconstruction. The commenters

stated that such an interpretation would not necessarily compromise the integrity of state plans; 

although the removal of an existing unit from a state cap-and-trade or trading system might 

disturb certain aspects of a state program, such disturbances could easily be dealt with through 

administrative mechanisms that would not discourage modifications and reconstructions. The 

commenters stated that, rather than aggregate, state-by-state guidelines, the EPA could eliminate 

the possibility of disruption by issuing category-specific, nationally applicable emission 

guidelines, as they have in the new and modified/reconstructed unit proposals with the result that 

the transition of a single EGU from existing status to modified or reconstructed status would 

have no effect on other existing units' compliance. The commenters stated that even under EPA's 

proposed goal-setting approach, EPA could allow states to administratively adjust their state 

goals upon receiving notice that an existing unit has commenced modification. The commenters

stated that the adjustment procedure could be codified in the state's approved plan, and therefore 

would not require a new federal rulemaking every time an existing unit decides to modify. The 

commenters stated that alternatively, under a cap-and-trade program, a state could automatically 

retire a predetermined quantity of allowances upon learning that a particular unit would exit the 

section 111(d) program upon modification; such a change also would not require additional EPA 

rulemaking, but would avoid the possibility that cap-and-trade programs would have too much 

"hot air" to stimulate emission reductions as newly modified units exit the program. The 

commenters stated that there are many other ways that states and EPA could encourage 

modifications at existing units without disrupting the implementation of the existing source 

guidelines, aside from the approach EPA has proposed.

Commenters stated that, regarding EPA's proposal that an existing source subject to Section 

111(d) will continue to be subject to those requirements even after it undertakes a modification 

or reconstruction and that this integrated system wide regulatory proposal would face serious 

implementation issues if affected sources were no longer subject to these plans, they do not agree 

with EPA's interpretation nor its extension to any existing source subject to any Section 111(d) 

plan. 

Commenters stated that they also raised concerns under a co-proposed option for modified 

sources regarding the EPA proposing the date for determining whether a unit is subject to a 

Section 111(d) plan is the date that the plan is initially submitted to the EPA; that is whether the 

modification occurs before or after the promulgation of a section 111(d) plan. The commenters

wished to reiterate their concerns with how these two section 111 plans will function together. 

The commenters stated that if alternative 2 of the modified proposal is promulgated by the EPA 
13

then a modified source will be subject to one of the two limits if the modification occurs before 

they submits their plan; however, recognizing the time it takes for a plan to be developed, the 

commenters and sources would be working together and plans under section 111(d) may be well 

underfoot. The commenters stated that they have concerns that some changes that may be chosen 

by a utility necessary to comply with section 111(d) may trigger a modification or reconstruction 

under this rule. The commenters stated that sources will be leery about making those changes, 

although they may be quite beneficial for the purpose of reducing CO2, if they know it will 

trigger the modify or reconstruct applicability. The commenters stated that the EPA has not 

thoroughly investigated and resolved the implications regarding the integration of these two 

proposals. The commenters stated that the EPA must separate these proposals and develop 

traditional section 111 proposals that follow the intent of the CAA to address existing sources 

and also modified and reconstructed sources. The commenters stated that on the same date as this 

proposal, the EPA proposed requirements for modified and reconstructed units under section 

111(b) and that they submitted comments regarding this proposal and have requested the EPA 

take into consideration the comments submitted under this proposal and under the 

modify/reconstruct proposal jointly with respect to both proposals due to the interconnected 

nature of the two proposed rules and the overlap in the comments.

Commenters stated that if any unit is converted from firing coal as its primary fuel to one that 

fires primarily natural gas, the conversion should be considered a modification for purposes of 

the carbon reduction program and the natural gas unit could therefore be regulated under section 

111(b) rules rather than a state's section 111(d) emission guidelines.

Commenters opposed the proposal to treat modified and reconstructed sources as existing 

sources under paragraph 111(d) and characterized this aspect of the proposal as arbitrary and 

capricious because commenters believed that the Act requires more stringent standards for 

modified and reconstructed sources than for existing sources, but commenters believed the 

proposed standards for existing sources are more stringent than the proposed standards for 

modified and reconstructed sources. Commenters stated that the proposed applicability 

provisions that would require modified and reconstructed sources to be classified as existing 

sources is inconsistent with the enforcement posture that the EPA has taken under the new 

source review (NSR) program where modifications force a departure from the world of existing 

sources.

Commenters asked if an EGU that is currently '"affected" (under the paragraph 111(d) standard 

for existing sources) were to commence modification or reconstruction prior to becoming subject 

to an applicable state plan, would EPA recalculate the state specific goal to reflect the absence of 

this no-longer "affected" EGU?

Commenters stated that the final rule should not attempt to regulate CO2 emissions from the 

same source under both section 111(b) and section 111(d). Commenters recommended that the 

final rule simply exempt modified and reconstructed sources from applicability under section 

111(b) regulations and allow states to retain the flexibility to exempt or assign regulatory 

applicability to modified and reconstructed sources as appropriate in their 111(d) plans. 

Similarly, commenters stated that new sources regulated under 111(b) should not also be subject 

to regulation under Section 111(d).
14

Commenters, air quality permitting authorities, opposed the proposed applicability provisions 

that would require an existing section 111(d) source to continue to be subject to state 111(d) 

standards even after it undertakes a modification or reconstruction. Commenters acknowledged 

that this proposed "once-in-always-in" policy is intended for compatibility with the proposed 

integrated system-wide regulatory approach, but commenters did not agree with this 

"interpretation" nor its extension to any existing source subject to any section 111(d) plan. 

The EPA should clarify that sources that modify or reconstruct prior to submission of a state plan 

are subject to section 111(d). Commenters stated EPA has clearly stated that sources that modify 

or reconstruct after becoming subject to a section 111(d) state plan remain subject to the state 

plan requirements, the Agency has not made it clear that sources modifying or reconstructing 

prior to submission of a state plan are subject to section 111(d) state plan requirements. 

Commenters said although one part of the proposal suggests that all modifications and 

reconstructions are subject to section 111(d), another portion of the proposal asserts that sources 

that modify or reconstruct after plan submission will continue to be subject to the plan. 

Commenters said EPA should expressly provide that sources modifying or reconstructing after 

the proposal of its emission guidelines and prior to state plan submission are still sources for 

which state plans must establish performance standards under section 111(d). Commenters said 

these sources should be subject to 111(d) state plan because the existing source BSER remains 

the system that will ensure the greatest pollution reductions from these EGUs considering cost 

and other statutory factors. Commenters said allowing such modified or reconstructed EGUs to 

exempt themselves from section 111(d) would potentially undermine the stringency of state 

plans by allowing "leakage" to modified or reconstructed sources. Commenters said such an 

approach would potentially require the recalculation of state goals and disrupt the development 

of state plans, all of which are premised on securing reductions from EGUs that were "existing" 

as of January 8, 2014.

Comment 4: Appropriate date for designating new and existing sources.

Response 4: See section IV.D of the final rule preamble of the CPP for a discussion of the new 

source designation date.

The following are summaries of the specific public comments under this comment:

Commenters stated that the agency cannot cite the January 8, 2014 proposal date as the 

paragraph 111(a) (2) date of proposal for differentiating applicability of section 111 standards to 

either new sources under paragraph 111(b) or existing sources under paragraph 111(d) because a 

federal court recently held in Nebraska v. EPA, 4:14-CV-3006, (USDC Neb. Oct. 6, 2014) that 

BSER determinations cannot be based on projects funded with federal dollars under the Energy 

Policy Act. Commenters also stated that the agency cannot cite the June 18, 2014 proposal date 

as the paragraph 111(a) (2) date of proposal for differentiating applicability of section 111 

standards to either new sources under paragraph 111(b) or existing sources under paragraph 

111(d) because the June 18 proposal applied only to a subset of the sources within the definition 

of "new source."
15

Commenters stated that the Agency cannot cite the January 8, 2014 proposal as the paragraph 

111(a)(2) date of proposal because the January 8, 2014 proposal for new sources did not 

constitute a system of emission reduction as required by paragraph 111(a)(1). Commenters stated

that proposed standard for new sources does not constitute a system of emission reduction 

because the proposed NSPS is void of federally enforceable requirements regarding the ultimate 

fate of the CO2 separated by EGUs for off-site disposal. Commenters asserted that the Agency 

cannot utilize authority granted under paragraph 111(d) (1) (A) (ii) to finalize a lawful section 

111(d) guideline based on an unlawful, prerequisite proposal under section 111(b).

Commenters submitted proposed revisions to proposed Subpart UUUU (requiring states to 

include requirements in their plans for NGCC units that become affected EGUs upon proposal of 

a revised GHG NSPS) in their Appendix A, with additions indicated in underlined text and 

deletions indicated in strikethrough text. Proposed revisions to proposed 40 CFR 60.5740, 5795, 

and 5800 seek removal of exemption for combustion turbines commencing construction on or 

before promulgation.

Comment 5: 111(b) units should not become 111(d) units in the future.

Response 5: The final rule does not include 111(b) units as affected units under 111(d). Future 

applicability of 111(b) units is outside of the scope of the rulemaking. 

The following are summaries of the specific public comments under this comment:

Commenters stated EPA's final guidelines should clearly state that units built after the CO2 

emission standards for new units were proposed and which are in compliance with those 

standards will not become 111(d) units at some point in the future. The commenters stated that 

States will submit compliance plans in 2016 that are designed to achieve the 2030 goal relative to 

the 2012 emission rate that EPA calculated for each state and it would be inconsistent with the 

CAA and unfair to states if EPA changed the goals (or determined that states were no longer 

making progress toward the goal emission rates) after compliance plans are approved to address 

new NGCC units that were built after January 8, 2014. The commenters stated that this would 

undermine state flexibility to use these units for compliance purposes; more importantly, this 

would undermine the certainty states and utilities need with respect to the final goals so that they 

confidently can invest resources to achieve them.

Comment 6: EPA ignored the nexus between sections 111(b) and 111(d) by developing an 

independent approach for existing source standards.

Response 6: We disagree with these comments. Our approach under section 111(b) for the 

BSER does not constrain our approach under section 111(d), but in any event, contrary to 

commenters’ assertions we applied a separate BSER for steam generators (building blocks 1, 2, 

and 3) and for combustion turbines (building block 3). The fact that the unused capacity in 
16

existing NGCC units allows them to be part of the BSER for steam generators does not mean 

that we are combining the two subcategories in a way that is contrary to section 111(d) or, for 

that matter, inconsistent with our approach under the re-proposal for the section 111(b) rule. As 

we discuss in the preamble, dispatch shifts from existing steam EGUs to existing natural gasfired EGUs in the amounts we include in the BSER for steam EGUs are well-established in the 

industry and thus are adequately demonstrated for purposes of determining the BSER. We 

explain in the preamble and Legal Memorandum why the section 111(b) and (d) have a different 

BSER and why the section 111(d) requirements cannot be said to be more stringent than the 

section 111(b) requirements.

The following are summaries of the specific public comments under this comment:

Commenters went on to say that EPA entirely ignored the nexus between sections 111(b) and 

111(d) by developing an independent approach for existing source standards. Commenters said 

that section 111 dictates that standards of performance for existing sources under Section 111(d) 

should be a more limited and flexible version of the standards of performance established by 

EPA for new sources under Section 111(b). Commenters said, if finalized, the proposed rule 

would do the opposite and unlawfully expand the scope of the existing source rule to new 

categories of sources while imposing standards of performance that are more stringent than those 

EPA has proposed for new sources. Commenters provided instances of the inconsistencies 

between the section 111(b) and 111(d) proposals:

• Commenters stated that EPA unlawfully combines coal- and natural gas-fired 

EGUs into a single source category for purposes of determining the best system of 

emission reduction adequately demonstrated. Commenters said, EPA flatly 

rejected this approach in its proposed regulation of new sources under Section 

111(b). Commenters said, when EPA first proposed standards of performance for 

GHG emissions from new fossil fuel-fired EGUs on April 13, 2012, it combined 

coal-fired EGUs and NGCC facilities into a single source category and, after 

conducting a single BSER analysis, proposed a standard of performance based on 

emissions levels with which NGCC facilities could "readily comply," but coalfired EGUs could not. Fed. Reg. 22,392, 22,410 (Apr.13, 2012). Commenters 

said, EPA subsequently withdrew that proposal, 79 Fed. Reg. 1,352 (Jan. 8, 

2014), and proposed separate standards for coal- and natural gas-fired EGUs, 79 

Fed. Reg. at 1,432. Commenters said, EPA based this reversal on its 

determination that both coal- and natural gas-fired EGUs would be viable options 

for new generating capacity and that different control technologies would be 

relevant to each. Id. at 1,434. Commenters said, this approach appropriately 

recognized that critical differences between coal- and natural gas-fired EGUs 

required distinct BSER analyses and different standards of performance. 

Commenters stated, here, in contrast, EPA has effectively ignored the differences 

between coal- and natural gas-fired EGUs and has aggregated these sources for 

the BSER analysis rather than subdividing them to determine BSER for each 

subcategory.
17

• Commenters stated that in the proposed rule, EPA acts inconsistently with the 

Section 111(d) proposal by unlawfully ignoring the source-specific nature of the 

systems of emission reduction evaluated by EPA in the section 111(b) proposal. 

Commenters said, instead, EPA relies on a BSER analysis that is focused 

primarily on emission reductions that are accomplished beyond the fence line of 

affected EGUs by other, unrelated "zero-emission" nuclear and renewable energy 

sources. Commenters said, indeed, many of the reductions would be 

accomplished by consumers of electricity rather that generators.

• Commenters stated that EPA turns the flexibility that should be afforded to 

existing sources on its head. Commenters said, as EPA explained when it 

promulgated implementing regulations for Section 111(d), "the degree of control 

reflected in EPA's emission guidelines will take into account the costs of 

retrofitting existing facilities and thus will probably be less stringent than 

corresponding standards for new sources." 40 Fed. Reg. 53,340. Commenters 

said, however, the EPA now has proposed binding emissions guidelines that are 

more stringent than the standards of performance it has proposed for new sources 

under Section 111(b). Commenters pointed out that EPA has proposed binding 

State-specific emissions targets for 30 States that are more stringent than the 

standard of performance for new coal-fired EGUs.

Commenters argued that EPA cannot impose more stringent standards on existing sources under 

section 111(d) than it has under section 111(b). Commenters argued that because both section 

111(b) and section 111(d) point to the same definition of "standard of performance," which 

references the application of BSER, EPA should use the same approach to determining the 

BSER under both section 111(b) and section 111(d) but should provide more, not less, flexibility 

in the establishment of BSER for existing sources. Commenters said that EPA even 

acknowledged that "the general principle (application of best adequately demonstrated control 

technology [now referred to as BSER], considering costs) will be the same in both cases," but 

"the degrees of control represented by [the existing source emission guidelines] will ordinarily be 

less stringent than those required by standards of performance for new sources." Commenters 

also noted that from Congress' original promulgation of CAA section 111(d), it was recognized 

that certain limitations may apply to existing sources that might not exist for new sources and 

that because of the limitations on existing sources, “more stringent requirements are imposed on 

new sources because engineering considerations allow for cheaper and more effective pollution 

control when the effort is incorporated in the design and construction of the facility." 

Commenters also said that EPA provides states the ability to deviate from emission guidelines 

when adopting emission standards for existing sources in various scenarios and that it would be 

unrealistic to assume that by providing this added flexibility for existing sources, EPA intended 

for the existing sources to be subject to more stringent standards than new sources.
18

2.2 PROPOSED APPLICABILITY VS. BROAD APPLICABILITY

This section addresses comments received on the proposed applicability criteria versus the broad 

applicability criteria.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Cover all fossil fuel fired units, and apply consistent applicability across all three 

section 111 EGU rules.

Response 1: The 111(b) applicability is consistent for all affected units. See section IV.A.1 of 

the NSPS preamble for a discussion of the broad applicability criteria for new, modified and 

reconstructed sources (steam generating units). See sections VIII.D and IX.A.3 of the 111(b)

NSPS preamble for a discussion of the broad applicability criteria for new, modified and 

reconstructed sources (combustion turbines). See section IV.D of the final rule preamble of the 

CPP for the EPA’s response on the broad applicability criteria for existing sources.

The following are summaries of specific public comments under this comment:

Commenters believed that all fossil fuel-fired EGUs in operation or that commenced 

construction as of January 8, 2014 should be considered affected units subject to the proposed 

rule, whether such units are owned by merchant generators, investor-owned electric utilities, 

public utilities or private cooperatives.

Commenters, the air quality permitting authority for the State of Ohio, responded to the EPA's 

request for comments on "a multitude of additional changes" to the applicability criteria; 

commenters stated that in combination with the proposed changes to applicability, commenters

found it difficult to determine exactly what the EPA is proposing. Commenters stated that it was 

difficult to determine if proposed applicability changes apply to modified and reconstructed 

sources, new sources, or existing sources. Commenters also stated that it was unclear if proposed 

revisions to applicability provisions were relevant to only GHG emissions or to all regulated 

pollutants under Part 60. Commenters stated that it was difficult to determine if the proposed 

changes will apply to other section 111 categories, and that it was difficult for the State of Ohio 

to grasp what the full impact of the changes will be. Commenters stated that it is imperative 

that the final rules for the three section 111 proposal reflect a clear, consistent, rational, and 

defensible set of applicability criteria across all three section 111 rules.

Commenters referred to comments previously submitted for the 111(b) proposal that stated 

section 111 requires the EPA to develop achievable standards based on what is achievable at the 

time they are proposed. Commenters acknowledged that some of the options considered in the 

proposal may seem reasonable in theory but opposed inclusion of numerous applicability 

options because commenters believed proposed regulations with numerous options are 

inconsistent with the EPA's statutory obligation to demonstrate that the associated standards are 
19

achievable for all the different sets of units implicit in each applicability option; commenters

cited the following case to support these concerns: Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 

427, 433-34 (D.C. Cir. 1973). Commenters asserted that the EPA cannot finalize any standards 

that the Agency cannot demonstrate are reasonable or standards for which EPA has not provided 

stakeholders sufficient opportunity for notice and meaningful comment.

Commenters recommended revisions to the criteria that a unit must be constructed for the 

purpose of selling and that the unit actually sells over one third of its potential electric output to 

the utility distribution system; commenters urged the EPA to include more uniform applicability 

criteria for steam units, IGCC units, and for combustion turbines across all three section 111 

proposals. Commenters stated that the criteria that (1) the unit must be constructed for the 

purpose of selling and that (2) the unit actually sells over one third of its potential electric output 

to the utility distribution system and that (3) the unit combusts fossil fuel for more than 10 

percent of its heat input should apply also to steam generating units because this simplification 

can reduce compliance costs and ensure that only those units that are actually intended to 

function as utility generating units are regulated under this section 111 category.

Comment 2: Consistent applicability with RGGI.

Response 2: See section IX.A.1 and 3 of the NSPS preamble for a discussion of the broad 

applicability criteria for new, modified and reconstructed sources.

The following are summaries of the specific public comments under this comment:

Commenters stated that the final rule should change or clarify the differences in applicability 

under the proposed rule and under the Regional Greenhouse Gas Initiative (RGGI) because the 

RGGI states have indicated their intention to use RGGI as a compliance mechanism, and the 

final rule should ensure that compliance with the RGGI cap will satisfy states' 111(d) obligations 

if the RGGI cap reflects the combined states' targets. Commenters subsequently provided several 

differences between RGGI and proposed 111(d) applicability criteria. Commenters, transmission 

system operators, stated that currently RGGI does not regulate hydro-electric imports from 

Canada and requested that the final guidelines allow transmission operators to continue to use 

hydro-electricity imported from Canada.

Commenters supported use of RGGI as the compliance mechanism for section 111(d) state plans, 

but commenters recommended that the EPA take specific action to facilitate the use of the RGGI 

paradigm. Commenters respectfully requested that the final rule include clarifications on how 

state plans should address differences in applicability in the RGGI program versus applicability 

in the final rule. Commenters specifically mentioned that the RGGI program in New York 

applies to all units that exceed 25 MW but the 111(d) proposal had a number of other criteria that 

must be considered to determine applicability. Commenters also asked that the final rule include 

clarifications on how state plans should address differences in RGGI's inclusion in the trading 

program versus exemption of new sources under the section 111 framework. Commenters

expressed concerns that exempting new units from compliance under RGGI would create 

electricity market distortions that would become increasingly problematic as CO2 allowance 
20

prices rise; a new unit with a higher emissions rate may be chosen for economic dispatch over an 

older unit simply because the new unit would not be required to purchase CO2 allowances under 

the section 111 applicability framework. Commenters recommended that the final rule should 

specifically permit states to manage compliance for both new and existing units under a single 

emissions limitation program to avoid unintended incentives, while retaining discretion as to 

whether new units would be included in a state plan.

Commenters, transmission system operators serving the RGGI states, requested that the final 

guideline address inconsistencies between proposed applicability under the federal guideline and 

the existing applicability provisions under RGGI because RGGI applies to all generators larger 

than 25 MW. Commenters believed these clarifications are needed in order for states to craft 

their section 111(d) plans. Commenters also stated that the treatment of new sources under RGGI 

is different than the proposed treatment of new sources under the section 111(d) proposal, and 

commenters were concerned that exempting new sources from section 111(d) plans will create 

electricity market distortions that would become increasingly problematic as the price of CO2 

allowances rise because a new unit with a higher emissions rate may be chosen for economic 

dispatch over an older unit simply because the unit would not be required to purchase CO2 

allowances. Commenters believed that the final federal guideline rule should allow states the 

option to either manage compliance for both new and existing units under a single trading 

program or under separate programs.

Commenters requested that the EPA consider inclusion of provisions in the final rule that should 

allow for a smoother translation of RGGI to a State Implementation Plan and a more aggressive 

climate pollution reduction target for New York. Commenters stated that Clean Power Plan only 

applies to existing power plants. In contrast, commenters noted that the carbon cap established 

through RGGI applies to all fossil-fuel fired generators in the region, both existing and those yet 

to be constructed. Commenters suggested that the Clean Power Plan should be adjusted to make 

clear for states proposing to utilize a mass-based system that system may allow for the inclusion 

of newly constructed and repowered facilities.

Comment 3: Base load fossil fuel heat input criterion and base load generator capacity criterion.

Response 3: See section IV.A of the 111(b) NSPS preamble for a discussion of the broad 

applicability criteria for new, modified and reconstructed sources (steam generating units). See 

section IX.A.3 of the NSPS preamble for a discussion of the broad applicability criteria for new, 

modified and reconstructed sources (combustion turbines). See section IV.D of the final rule 

preamble of the CPP for the EPA’s response on the broad applicability.

The following are summaries of the specific public comments under this comment:

Commenters supported the proposed applicability of 250 MMBtu per hour fossil fuel heat input 

because this threshold is identical to the applicability threshold for new, modified and 

reconstructed electric utility steam generating unit, as defined in 40 CFR 60.4Da. Commenters

interpreted the proposed 73 MW applicability threshold as an electrical output threshold (rather 

than a heat input threshold expressed in millions of Joules per second) and commenters
21

supported establishing the applicability threshold so that the final rule only applies to units with a 

net rated capacity greater than 73 MW.

Commenters stated that four 25 MW coal units, Hamilton (Units 7 and 8) and Orrville (Units 10 

and 11), were improperly included in calculation of the State of Ohio's section 111(d) goal 

because these units do not have the physical ability to operate non-stop at full nameplate capacity 

for an entire year.

Commenters requested that the final rule clarify the difference between the 73 MW baseload 

rating applicability threshold for affected units in the regulatory text and the 25 MW nameplate 

capacity referenced in the Goal Computation TSD at 27, n.1, 30.

Commenters, project based agencies that support the supply, transmission, and delivery of 

electricity to small towns, were concerned about the effect of the proposed rule on small power 

plants, economic growth, plant closures, and lack of credit for energy efficiency and renewable 

energy projects completed prior to the baseline year. Commenters stated that the final rule should 

make clear that states can and ought to subcategorize effected EGU sources to address small 

municipal systems and small unit concerns. Commenters requested that the final rule set the 

affected EGU threshold at greater than 73 MW generating capacity and not 250 MMBtu/hr of 

heat input capacity. Commenters requested that the final rule include less than 10 MW existing 

hydro in goal calculations.

Commenters, community owned, not-for-profit utilities with two coal/petroleum coke/biomassfired units and two natural gas-fired units, requested that all EGUs under 100 MW capacity be 

exempted from the final federal guideline.

Commenters generally supported including operating criteria for determining whether the 

proposed Subpart KKKK standards would apply to new stationary combustion turbines. 

Commenters remarked that operating criteria would help to insure that turbines that are used only 

infrequently or in emergencies, and therefore would have relatively minimal emissions, are not 

subject to the standards.

Comment 4: Electricity sales, percentage and total annual thresholds.

Response 4: The final applicability criteria are not retrospective. See sections IX.A of the final 

rule preamble of the NSPS rulemaking for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters, state air quality permitting authorities, opposed omission of the criteria for 

retrospective, actual electrical sales in the regulatory text for the proposed section 111(d) 

standard because omission of these criteria is inconsistent with the preamble language describing 

applicability for existing sources at 79 FR 34854 and also inconsistent with the proposed rule for 

new sources at 79 FR 1511. Commenters stated that this inconsistency was even more apparent 

because the proposed applicability criteria for existing combustion turbines at 79 FR 34954 
22

continues to include the sales criteria proposed for new sources. Commenters stated that the 

discrepancy would impact units in the state of Ohio and provided Hamilton Unit 9, ORIS 2917 

as an example of an EGU that would be subject to the 111(d) rule as proposed but that would be 

excluded from the proposed section 111(d) rule if the sales criteria proposed for new sources was 

also included in existing source applicability criteria. 

Commenters stated that the final rule should include a clearly worded exemption for steam units 

that are used for peaking cycles. Commenters stated that the preamble to the proposal included 

language that indicated peaking steam units would be exempt from 111(d) emissions standards, 

however commenters believed that the language in the proposed rule text was not consistent with 

the stated intent (relevant to exemption of small steam units with very low capacity factors), and 

commenters provided recommended revisions to the proposed regulatory text to make the 

regulatory text consistent with the intent stated by the Agency in the preamble at 79 FR 34854.

Commenters stated that there were inconsistencies between applicability criteria described in the 

preamble compared to the proposed regulatory text related to the 219,000 MWh sales threshold 

(preamble at 79 FR 34854 vs. regulatory text at 79 FR 34954) because the preamble phrase, "was 

constructed for the purpose of supplying one-third or more of its potential electric output and 

more than 219,000 MWh net-electric output to a utility distribution system on an annual basis[,]" 

is inconsistent with the regulatory text phrase, "has the potential to generate and supply at least 

219,000 MWh per year[.]" Commenters noted that there are several units in Iowa there were 

identified as "likely affected units" in the proposal; however, these units have never sold more 

than 219,000 MWh in a calendar year and commenters cited two examples (Streeter Station Unit 

7 and Muscatine Unit 7); commenters were concerned that these inconsistent descriptions of the 

proposed applicability criteria could adversely affect the goal calculation for Iowa. Commenters

requested that the final rule clarify these applicability criteria so that states can easily determine 

which units are affected and which are not, and commenters specifically requested that the EPA 

work with IDNR when the applicability criteria are more clearly defined so that EPA's list of 

affected sources is accurately reflected when the state goal is calculated for the final rule.

Commenters stated that the EPA should clarify the actual sales criteria for affected EGUs 

because the proposed text in section 60.5795 (b) (l) does not include the "and supplies" language 

included in (b) (2). Commenters stated that including "and supplies" would be consistent with 

EPA's intent to include an actual sales threshold in the "affected EGU" criteria for existing steam 

boilers. 

Commenters supported setting a MWh limit for an affected unit, as discussed at page 34854 of 

the proposal if the final guidelines include an exemption for smaller coal units (<100 MW 

capacity) because these small units provide great value in meeting summer peak loads while the 

US transforms to an increased renewable energy portfolio and because these units help address 

reliability issues, and commenters believed that these units will naturally retire over the next 

several decades as they reach the end of their useful lives and as additional technologies becomes 

available to address the reliability gaps between renewables and the current energy demand.

Commenters recommended that the final rule should define a "small utility" using the same 

definition set forth at 16 USC 824(f): a rural cooperative that sells less than 4,000,000 megawatt 

hours of electricity per year.
23

Commenters opposed the proposed deletion of the net sales criterion because without this 

criterion, the 111(d) standard will apply to limited-use oil-fired units. Commenters stated that the 

final rule should create an exemption for limited-use oil-fired units similar to the MATS rule's 

eight percent capacity factor exemption because these units only operate during emergency 

situations and are critical to grid stability. Commenters believed a 111(d) exemption similar to

the MATS exemption is reasonable and appropriate because these units do not run frequently, 

and the MATS exemption recognized that these units would be retired instead of retrofitted with 

expensive control technologies. Similarly, commenters stated it is reasonable and appropriate to 

exempt these limited-use oil-fired units from section 111 regulations because there is no control 

technology retrofit that would address CO2 emissions from these units and heat rate 

improvements would prove ineffective given the limited operations of these units. Commenters

stated that it would be unworkable for states to attempt to address emissions from these units 

since the proposed section 111(d) building blocks do not have any impact on these units: heat 

rate improvements at coal units will not affect oil-fired units; increased use of NGCC units will 

not displace generation from emergency-use units; similarly increased renewables will not 

displace generation from emergency-use units because they are not competing to serve the same 

load; finally, end-use efficiency will not reduce generation from these emergency-use units 

because they only run during periods of customer demand that are immune to efficiency 

measures like after hurricanes or during an unexpected cold snaps. Commenters concluded that 

the proposed BSER for existing units under section 111(d) is not the best system of emission 

reduction that has been adequately demonstrated for limited-use oil-fired units. Commenters also 

stated that it is inappropriate to apply the standard to limited-use oil-fired units because one or 

more of these units may not have been required by the system operator in 2012 when the 

baseline for each state was established.

Commenters stated, the EPA's proposed changes to the applicability requirements for subpart Da 

units should not subject limited-use oil-based units to regulation under CAA section 111(d).

Commenters stated, reliability-critical, limited-use oil-based units should not be subject to 

numeric standards under CAA section 111(b) or (d).

Commenters opposed inclusion of 25 MW units in the proposed rule and goal setting 

calculations proposed for the State of Ohio because it is not feasible for these units to run 8,760 

hours per year as implied in the EPA's assumption that the existing source standard will apply to 

these peaking units; commenters disagreed with the EPA's contention that the 25 MW net sales 

criterion and the 219,000 MWh sales criterion are functionally the same.

Commenters stated that the proposed inclusion of units with 25 MW nameplate capacities is 

incorrect regardless of how the final rule amends the definition of affected source because the 

proposal inappropriately included units that are 25 MW nameplate capacity in the goal 

calculation for the State of Ohio. Commenters stated that it is not feasible for a 25 MW unit to 

produce 219,000 MWh per year because no unit has the physical ability to operate non-stop at 

full nameplate capacity for an entire year without outages for routine maintenance. Specifically, 

commenters stated that Hamilton Units 7 and 8 have operated at an average load factor of under 

30 percent during the past two years, and the Orrville Units 10 and 11 have operated at an 

average load factor of under 50 percent during the past two years; the final rule should remove 

Hamilton Units 7 and 8 and Orrville Units 10 and 11 from Appendix 7 and recalculate Ohio's 
24

baseline and goal computation without the inclusion of these units. Similarly, commenters stated 

that Hamilton Unit 9, a 50.6 MW nameplate capacity unit, should be excluded from Ohio's 

baseline because has not sold more than 219,000 MWh in any year since and including USEPA's 

baseline year.

Commenters, state air quality permitting authorities, stated that the final guideline should not 

rely on an assumption that increased utilization could be exercised at non-base load combined 

cycle units because North Carolina has two small NGCC facilities that do not operate as base 

load assets: one operates as a peaking unit with a capacity factor less than 5 percent, and the 

other was originally designed as a CHP plant and operates with a capacity factor of less than 15 

percent. Commenters stated that these types of facilities may not be able to sustain an annual 

operating load of 70 percent, and commenters requested that EPA modify the proposed guideline 

to exclude specific NGCC plants that operate below a specified threshold such as a 15 percent 

capacity factor on an annual or monthly basis.

Comment 5: Gross vs. net for determining electricity generation applicability.

Response 5: Net electric sales is appropriate for applicability purpose because it is a better 

measure than gross output of if the unit meets the general applicability size criterion. See section 

III.F of the NSPS preamble for a discussion of the use of gross versus net output for determining 

applicability. See section VI.C of the CPP preamble for this rulemaking for a discussion of the 

use of gross versus net output for determining applicability.

The following are summaries of the specific public comments under this comment:

Commenters supported using gross MWh criteria for determining applicability of the standard to 

stationary combustion turbines because gross MWh applicability criteria places the entire focus 

on the combustion turbine, not on sales to the grid and not on station service energy that may or 

may not be directly relevant to the combustion turbine; because gross MWh applicability criteria 

can utilize the same measurement location used for compliance as proposed at section 

60.4373(d); because gross MWh applicability criteria appear to match the intent of the example 

in the proposed "potential electric output" definition, which refers to a "35% efficient stationary 

combustion turbine" (the efficiency of the turbine itself, not efficiency based on sales to the 

electric grid).

Comment 6: Support for and opposition to applicability to simple cycle turbines

Response 6: See sections IX.A and B of the final preamble for the NSPS rulemaking for the 

EPA’s response to this comment. Also, see section IV.D of the final rule preamble of the CPP 

for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:
25

Commenters stated that simple cycle units should be included in the regulation because there 

could be over utilization of these units (with exempt emissions) to provide generation without the 

associated emissions against the states' cap. Commenters recommended that simple cycle units 

be included under the section 111 regulations to ensure all emissions from the power sector are 

managed for reductions. 

Commenters stated that section 111 prohibits promulgation of standards that are based on 

assumptions about the future deployment of renewable energy or energy storage or increased 

demand response that could substitute for simple cycle capacity.

Commenters stated that simple-cycle CTs should not be subject to standards that do not 

recognize the range of services these units provide to the grid and because it is not 

technologically feasible for simple cycle units to continue to provide these services while 

achieving efficiencies equivalent to combined cycle units. Commenters stated that the energy 

supply protocols that ensure grid stability require that units held in the ready-mode as "spinning 

and non-spinning reserves" must be available within 10 minutes of dispatch and stated that 

NGCC units cannot satisfy this requirement and described a broad range of system operating 

scenarios that currently rely on the unique capabilities of simple cycle units including support for 

renewables. Commenters stated that renewables are an intermittent resource and that the only 

resources that can be reliably dispatched quickly enough to compensate for significant swings 

are simple-cycle CTs and hydro. Commenters concluded that if EPA's goal is to foster the 

development of renewable energy, imposing strict limits on the main backup generating source 

(simple cycle CTs) may be counterproductive. 

Commenters stated that EPA proposes to include as an affected source existing NGSC units 

operating at a 33% or greater capacity factor and that are constructed for the purpose of 

supplying more than 219,000 MWh nonelectrical output to the grid. Commenters cited reasons 

they set in their comments to EPA's proposed New and Modified Unit NSPS, and herein 

objecting to this inclusion of NGSC units as affected sources.

Commenters stated and concurred that EPA should exclude simple cycle turbines both from the 

category of affected EGUs and from EPA's emission reduction goal calculations (99 While EPA 

asserts that it has excluded from its goal computations any simple cycle turbines that failed to 

qualify as an affected EGU, at least some simple cycle turbines do satisfy the applicability 

criteria and are included in the proposed rule. See 79 Fed. Reg. at 34,895 n.260) as it proposed to 

do in the initial April 2012 proposal for newly constructed fossil fuel-fired EGUs. See 77 Fed. 

Reg. 22,392. Commenters believed that treating simple cycle turbines as affected EGUs in the 

same manner as NGCC facilities is inconsistent with their role in supplying power, will 

needlessly subject owners and operators of simple cycle turbines to an unprecedented post hoc 

applicability test, and will reduce the flexibility that States will need to cope with the dramatic 

increases in renewable power generation that will be required to meet EPA's emission reduction 

targets. Alternatively, commenters stated, if EPA is determined to regulate CO2 emissions from 

existing simple cycle turbines, commenters requested that EPA adjust the emissions guidelines 

or emission reduction targets to reflect the emissions limits that can be achieved by existing 

simple cycle turbines, now and under projected future conditions where increased renewable 

generation may require them to increase capacity.
26

Commenters explained that simple cycle turbines play a fundamentally different role in energy 

generation than NGCC turbines. Commenters described how simple cycle turbines play a critical 

and unique role in providing peaking power and assuring grid reliability, describing how those 

simple cycle turbines can cold start quickly, easily scale through loads, and start and stop several 

times per day. Commenters said this flexibility allows them to fill the unique role of providing 

gap-filling auxiliary power at times of high demand or when the grid is otherwise under stress. 

79 Fed. Reg. at 34,968 ("The power output from these simple cycle combustion turbines can be 

easily ramped up and down making them ideal for "peaking" operations."). Commenters believed 

that no other form of power generation is capable of filling this role. 

Commenters continues, stating that combined cycle turbines are designed for baseload or

intermediate load power, meaning that they are very efficient and have a high utilization rate, 

and in contrast, simple cycle turbines provide peaking power, meaning that their hours of 

operation are unpredictable, and they rarely operate at full load, the most efficient operating 

mode. Commenters said the larger - and increasing - role that renewable power sources play 

requires significant support from simple cycle turbines, which can start-up quickly to 

compensate for highly variable and often intermittent generation from solar and wind 

facilities. Commenters stated that these renewable energy facilities are subject to several factors 

beyond their control that impact their reliability, including, but not limited to fluctuating wind 

speeds, cloud cover, and even the approach of birds. Commenters said, as renewable energy 

takes on a larger share of power generation, the need for reliable and flexible simple cycle 

turbine operations will only increase. Commenters noted, indeed, the increased need for peaking 

power from simple cycle turbines may well be driven by this rulemaking, given EPA's focus on 

increased renewable energy generation in Building Block 3. See 79 Fed. Reg. 34,866-70.

Commenters stated that in the January 2014 proposal for newly constructed fossil fuel-fired 

EGUs, EPA reversed course and eliminated the previously proposed exemption for simple cycle 

turbines out of an unfounded fear that they will be used for baseload or intermediate load 

generation. 79 Fed. Reg. at 1459. Commenters noted that this proposal includes the same 

applicability criteria for stationary combustion turbines as the January 2014 proposal. See 79 

Fed. Reg. at 34,954 (proposed 40 C.F.R. section 5795(b) (2)). Commenters stated that simple 

cycle turbines are simply not interchangeable with combined cycle turbines in this way. 

Commenters said, as EPA recognizes, the use of simple cycle turbines for baseload power would 

involve much higher fuel and maintenance costs to generate the same amount of electricity as 

more efficient combined cycle turbines. Commenters stated, although no owner or operator 

would intend to run a simple cycle turbine for baseload power generation, as explained in more 

detail below, the changing nature of America's electricity supply and the role of simple cycle 

turbines in providing power on an as- needed basis may require more flexibility in the future. In 

light of these important differences between simple cycle and combined cycle turbines, 

commenters believed that EPA should reinstate the exclusion for simple cycle turbines that it 

originally proposed in April 2012.

Alternatively, it is commenters’ position that if EPA must regulate simple cycle turbines, it must 

establish separate and achievable standards of performance, adjusting the applicable emissions 

guidelines and emission reduction targets to fully account for the projected future usage of these 

facilities as well as the emission reductions that they can achieve in practice. First, commenters 

explained that simple cycle turbines may operate more frequently as renewable power generation 

increases amid baseload plant retirements. Commenters elaborated that EPA relies on data 
27

showing that only a small portion of simple cycle turbines met the proposed applicability criteria. 

See 79 Fed. Reg. at 34,895 n.260; see also 79 Fed. Reg. at 34,797 (asserting that only 0.2% of 

simple cycle turbines sold more than one-third of their potential electric output to the grid over a 

three-year averaging period). Commenters said, however, the data on which EPA relies dates 

back to 2000, 79 Fed. Reg. at 34,797, and does not account for the recent increases in renewable 

power generation and projections that this reliance on renewable power will increase due to the 

retirement of coal plants due to existing EPA regulations or the changes in coal-fired electricity 

generating capacity and renewable energy generating capacity that would occur if this rule were 

finalized. Commenters stated, although EPA projects that existing NGCC facilities can increase 

generating capacity, new NGCC plants will be needed to replace at least some of the retired 

baseload power cause by this proposed rule, MATS, and other regulations. Commenters stated 

that there is often a significant time lapse between planning and the actual start-up of operations 

due to burdensome and time-consuming State and federal regulations and lawsuits to block 

projects. Commenters said this means that grid reliability will likely become more variable due 

to the increased use of renewable power and the expected time lag in replacing retired coal-fired 

electricity generation. Thus, commenters said it is likely that simple cycle turbines will have to 

be utilized more frequently than they have been in the past, both to provide grid stability until 

adequate non-renewable replacement baseload generation is in place and to accommodate 

increased reliance on intermittent renewable energy. Commenters noted, although most forecasts 

view future electricity demand as being relatively stable, the sources used to meet that demand 

are already beginning to change. Therefore, commenters posited, if EPA is intent on regulating 

existing simple cycle turbines, then it should do so in a way that accounts for the changes in 

operation that EPA's rules are likely to cause. Commenters remarked that EPA must establish a 

separate subcategory for simple cycle turbines, and in the event that EPA withdraws the 

proposed rule and proceeds instead with source category-specific, inside the fence line emissions 

guidelines, it must establish a separate subcategory for existing simple cycle turbines. 

Commenters said simple cycle turbines which operate at lower, less efficient loads and cannot 

use a heat recovery steam generator -cannot meet the same emission limits as NGCC 

turbines. Commenters noted EPA asserted in the January 2014 proposal that "advanced simple 

cycle combustion turbines have a base load rating of 1,150 lbs CO2/MWh ..." 79 Fed. Reg. at 

1485 (emphasis added) (citing EIA's Advanced Energy Outlook 2013 report). Thus, commenters 

stated, even under the most efficient operating conditions, the best performing simple cycle 

turbines cannot achieve the emissions limits that EPA has previously proposed for all stationary 

combustion turbines. Commenters also stated, under the variable and less efficient conditions 

associated with the generation of peaking power, emissions will necessarily be higher. Further, 

commenters said given their role in providing peaking power, there are no technological 

advances that would allow simple cycle turbines to achieve the same emissions levels as NGCC 

turbines operating at or near full capacity. Commenters noted that combined cycle turbines 

increase efficiency and reduce emissions by capturing exhaust heat from the gas turbine and 

using it to produce additional electricity from a steam turbine. But when the heat recovery 

system and steam turbine are not operating, commenters noted that the NGCC facility essentially 

operates as a simple cycle turbine with a corresponding loss in efficiency. Thus, commenters 

stated, as long as simple cycle turbines are relied upon to provide peaking power, they cannot 

meet standards of performance designed for NGCC facilities. Commenters said if EPA 

determines that it is necessary to regulate simple cycle turbines under Section 111(d), it must 

account for these fundamental differences between simple cycle and NGCC turbines. 
28

Commenters asserted that Section 111 authorizes EPA to "distinguish among classes, types, and 

sizes within categories of new sources" when establishing standards of performance. 42 

U.S.C. 7411(b) (2). Commenters said Section 111(d) gives EPA and the States further authority 

to base an existing source's standard of performance on the source's remaining useful life and 

other relevant factors. 42 U.S.C. section 7411(d) (1) (B). Commenters stated, if simple cycle 

turbines are included as affected EGUs, EPA and the States could use this provision to establish 

different emissions guidelines and standards of performance for simple cycle turbines that reflect 

both the emission control technologies available to them and efficiency challenges associated 

with providing peaking power. Commenters said such an approach is fully consistent with 

Section 111(d) and would allow EPA to fully incorporate the different roles played by simple 

cycle and combined cycle turbines and the different emission reductions that can be achieved by 

each.

Commenters stated that EPA should explicitly exclude simple cycle combustion turbines ("CTs") 

from regulation under the CPP to avoid confusion regarding the rule's reach, explaining that to 

be exempted from the Proposed Rule's affected source definition, a CT would have to be 

constructed for the purpose of supplying, and supply, less than one-third of its potential electric 

output to the gird, and most CTs are not constructed to provide more than one-third of their 

potential output to the grid because a NGCC unit is more economic than a CT unit expected to 

operate at or above a 33 percent capacity factor. Thus, commenters concluded, very few, if any, 

CTs should qualify as an "affected unit" under the Proposed Rule, and an explicit exemption or 

exclusion of CTs from the definition of affected sources would provide clarity regarding EPA's 

intent. Commenters added that such a clarification would avoid the confusing determinations of 

whether a CT was constructed for the purpose of supplying one-third or more of its potential 

electric output to the grid and whether a CT could become an affected source due to increased 

utilization necessary to ensure grid integrity. Commenters continued, stating that explicitly 

exempting CTs is prudent because they are critical to the safe and reliable operation of the 

electricity transmission grid. Commenters said their ability to come on-line and ramp up to full 

energy production in ten minutes or less is often relied upon to balance out the variability in RE 

generation and to replace power if an intermediate or base load power plant trips off-line. 

Commenters stated, while CTs historically have operated at low capacity factors, the generation 

paradigm shift the Proposed Rule would precipitate may change CT operations and capacity 

factors, especially in the potentially tumultuous early years of the CPP's implementation. 

Commenters stated, for continued safe and reliable electric service, it is imperative that EPA 

allow utilities and regional transmission operators to run CTs unfettered by the Proposed Rule's 

provisions. Commenters added that should EPA decline to explicitly exempt CTs, clarification in 

a number of areas is necessary, including clarifying 1) how lower utilization CTs can 

demonstrate that they were not constructed to supply one-third or more of their potential electric 

output and more than 219,000 MWh net-electrical output to the grid; 2) whether a source that 

was not constructed to supply one-third or more of its potential electricity output and more than 

219,000 MWh net-electrical output to the grid could become an affected source by subsequently 

supplying power to the grid in excess of these thresholds; 3) what constitutes an "affected 

source" with regard to several other source types; 4) the 73 MW base load rating threshold for 

affected units given its Goal Computation TSD references a 25 MW nameplate capacity 

threshold; and 5) clarify its treatment of under-construction high utilization CTs, OG steam, and 

coal, noting these units could qualify as affected sources, but the Proposed Rule does not appear 

to include them in states' baselines.
29

Commenters stated that EPA should explicitly exclude simple cycle turbines as it initially 

proposed to do in the CAA section 111(b) rulemaking because 1. Simple cycle turbines serve a 

completely different function than NGCC facilities and should not be regulated as part of the 

same source category, and 2. Simple cycle turbines cannot achieve the same level of CO2 

emissions as NGCC facilities. Commenters offered alternatively, EPA must appropriately 

account for the higher emissions associated with simple cycle turbines in setting state emissions 

rate targets and to do so, EPA must also account for the increased demand for peaking power that 

will accompany the projected growth in projects for intermittent renewable energy sources such 

as wind and solar.

Commenters stated, section 111(b) standards for combustion turbines must be achievable at the 

time of proposal.

Commenters stated, simple-cycle CTs should not be subject to section 111(b) standards that do 

not recognize the range of services these units provide to the grid.

Commenters stated, consistent with EPA's statutory obligations, standards for new simple-cycle 

CTs units must be achievable when proposed.

Commenters responded to the proposal's request for comments on whether the proposed net sales 

criteria is sufficient to account for the projected increase in simple cycle capacity 

factors attributable to state and local mandates for increased reliance on renewable 

generation. Commenters stated that it is unlikely that any stakeholder would have credible, 

reliable data on the extent to which simple-cycle CTs will be used to support renewable 

generation in the future because any such analysis would be dependent on numerous statespecific assumptions about RPS standards and the future demand for electricity, future wholesale 

electric prices and the costs of new simple-cycle CTs, among others. Commenters, an air quality 

permitting authority in a state with a 20 percent renewable portfolio standard, indicated that the 

33 percent capacity factor would not be sufficient for the category of generators (i.e., flexible 

generators) used in California to support renewable generation. Commenters divided generating 

assets used in California into three categories based on annual capacity factors: baseload (60 to 

100 percent capacity factors); flexible (33 to 60 percent capacity factors); and peaker (below 33 

percent capacity factors). Commenters stated that the flexible category encompassed simple 

cycle operations (either during bypass of the HRSG on combined cycle units or on combustion 

turbines that can only operate in the simple cycle mode). Commenters described flexible 

generators as an emergent type of generating capacity integral to the increasing development of 

renewable resources in California. Commenters stated that flexible EGUs share three primary 

characteristics: dispatch ability/load-following, fast-starting, and fast-ramping. Commenters

stated that to integrate renewable resources, the electricity system must have sufficient dispatch 

able EGUs that are available to respond to varying system needs when called upon. Commenters 

stated that since renewable resources can come on the system or drop from the system very 

quickly, the electricity system needs large amounts (proportional to the RPS) of dispatch able

EGUs that have fast start capability, that can ramp (up or down) very quickly, and that can turn 

down to lower output to maintain grid stability for dynamic demand and supply conditions. 

Commenters stated that EGUs that can come on-line in 10 minutes or less are increasingly 

needed and acknowledged that EGUs that operate in this ready-state manner are less thermally 
30

efficient, but that in combination with the renewable resources that they support provide systemwide emissions reductions. 

Commenters stated that the most important assumption in a prospective analysis of the impacts 

of RPS on simple cycle operations may relate to the potential impacts of EPA's final GHG 

standards for new and existing natural gas-based units because these standards will be significant 

factors influencing which flexible gas-based units are used to support renewables generation. 

Commenters explained that if states choose to increase utilization of existing NGCC units to 

comply with the state-specific emission rate goals proposed in the 111(d) guidelines, it is likely 

that simple-cycle CTs (both new and existing) would be needed to facilitate renewables 

integration; conversely, if EPA's final standards for new units under section 111(b) place 

significant operating limits on simple-cycle CTs, then existing CTs and existing NGCCs could 

play a larger role in renewables integration. 

Commenters stated that the final rule should clarify that the heat recovery steam generator 

(HRSG) is part of the combustion turbine.

Comment 7: Year to year changes in applicability determinations for turbines, and “once in, 

always in”.

Response 7: The final applicability does not use retrospective criteria. Therefore, units will not 

be moving in and out of applicability based on operating parameters. See section IX.A of the 

final preamble for the NSPS rulemaking for the EPA’s response to this comment. 

The following are summaries of the specific public comments under this comment:

Commenters stated that revisions and clarifications are needed on applicability requirements for 

gas turbines and treatment of these units when operations fluctuate across applicability 

thresholds. Commenters stated that the final rule should increase the applicability threshold for 

simple cycle turbines from 33 percent to 40 percent to accommodate increased reliance on 

renewables because system operators must maintain sufficient fast-ramping resources at partial 

load to balance rapid or unexpected dips in supply from intermittent renewable generation. 

Commenters also stated that simple cycle CTs can provide this fast-ramping capability and also 

provide important ancillary services, including frequency regulation (smoothing minute-tominute generation and load variability to maintain voltage and system frequency), and load 

following (smoothing hour-to-hour generation and load variability). 

Commenters stated that final rule should include procedure by which states can update their 

plans to allow simple cycle natural gas units to be added or removed from the plan, as 

appropriate because the proposed rule does not specify whether an initially exempted gas-fired

unit that increases its capacity factor above the applicability threshold (for example, due to 

significant re-dispatch or increased electricity demand) must be included in an updated state 

plan. Commenters stated the proposal does not specify whether a unit that was initially included, 

but that later reduces its capacity factor below the threshold must continue to meet the 

requirements of a state plan. Commenters recommended that the final rule should require states 
31

to update state plans at least every three years to revise the set of units included in the plan in 

accordance with the final threshold.

Commenters stated that the final rule should clarify the applicability provisions for combustion 

turbines because the proposed rule did not clearly and consistently specify which fossil-fired 

units were affected sources. Commenters stated that the final rule should clarify that a 

combustion turbine must meet all four of the applicability criteria listed in proposed section 

60.5795(b) (2), and commenters stated that the final rule should clarify that a source that was 

constructed to supply less than one-third of its potential electricity output and less than 219,000 

MWh net-electrical output per year does not become an affected source by subsequently 

supplying power to the grid in excess of these thresholds. Commenters also requested that the 

final rule clarify that a stationary combustion turbine that exceeds both supply thresholds for a 

given 3-year rolling average period, thus becoming an affected EGU, would cease to be an 

affected EGU if, in a later 3-year rolling average period, output falls below these thresholds. 

Commenters also requested that the final rule clarify how lower utilization combustion turbines 

can demonstrate that they were not constructed to supply one-third or more of their potential 

electric output and more than 219,000 MWh net-electrical output to the grid. 

Commenters stated that the EPA should also clarify that when a unit is de-rated such that the 

potential electric output falls under the 25MW net capacity or 219,000MWh net output 

threshold, the unit no longer qualifies as an affected EGU. Commenters stated that this 

clarification is necessary to understand the proper regulatory treatment of a specific EGU 

operated by them (Healy Unit I), and commenters provided relevant applicability facts about 

Healy Unit I and other units in the commenters’ fleet. 

Commenters asked, since the definition of "affected EGU" excludes most simple cycle 

combustion turbines (SCCT) due to the limited amount of time that they operate, Has the EPA 

considered whether a non-affected unit could become an affected unit (i.e., by operating above 

the 33 percent capacity factor making it subject to the 111(d) plan applicability criteria)? 

Commenters also asked, if the unit were re-designated as affected, would EPA recalculate the 

state-specific goal?

Commenters also requested that the final federal guidelines provide applicability clarifications 

for situations where successive annual or triennial average capacity factors fluctuate across the 

proposed applicability thresholds. Commenters asked how goals and plans would be affected by 

such applicability fluctuations. Commenters also stated that the final guidelines must include a 

mechanism for adjustments to state goals upon changes to the set of sources that meet 

established applicability criteria. Commenters, the permitting authority for the State of Vermont, 

stated that currently Vermont has no affected sources under the proposed applicability criteria, 

but that it is possible that an EGU in the state could meet the proposed applicability criteria in the 

future, and commenters requested that the EPA provide clarification on this situation in the final 

federal guidelines.

Commenters asked whether the preamble statement that the unit must actually sell at least 

219,000 MWh per year is a once-in-always-in test or whether discrete averaging periods could 

yield differing applicability results for this criteria. 
32

Comment 8: Allow requests for federally enforceable permit limit on annual generation.

Response 8: The applicability in this final rule includes an exemption for CHP units subject to a 

permit restriction limiting electric sales. This exemption does not apply to electric only EGUs. 

See section III.C and IV.A of the final preamble for the NSPS rulemaking for the EPA’s 

response to this comment for steam generating boilers and IGCC, and section IX.D of the final 

preamble for the NSPS rulemaking for the EPA’s response to this comment for CHP.

The following are summaries of the specific public comments under this comment:

Commenters requested that the EPA clarify whether an operator of an EGU can request a 

federally enforceable permit limit on annual generation to avoid applicability under the section 

111(d) rule.

2.3 APPLICABILITY ISSUES RELATED TO EGUS THAT FIRE BIOMASS OR 

OTHER NON-FOSSIL FUELS

This section addresses comments received on applicability issues related to EGUs that fire 

biomass or other non-fossil fuels.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Support for or opposition to including biomass units.

Response 1: See section III.D of the NSPS preamble for a discussion of biomass and other nonfossil fuels. See section IV.D of the final rule preamble of the CPP for the EPA’s discussion of 

biomass and other non-fossil fuels.

The following are summaries of the specific public comments under this comment:

Commenters were specifically concerned about how the inconsistency between the proposed 

section 111(b) rule's applicability and the proposed section 111(d) rule's criteria would make 

biomass-fired units subject to CO2 regulations; commenters did not believe that sources that 

primarily fire biogenic fuels should be subject to CO2 regulations, and commenters did not 

believe that the proposal contained any justification for introducing the inconsistency in the 

111(d) rule and making biomass-fired units subject to the 111(d) rule.

Commenters opposed the proposed removal of the ten percent fossil fuel criterion because 

without this exemption the 111(d) standard will apply to biomass-fired units. Commenters stated

that the impact of the proposed deletions on biomass units could not be fully assessed because 
33

the proposal did not describe how biomass units would be treated in state plans, and commenters

recommended that the Agency issue a separate rulemaking that addresses all biomass issues 

holistically. Commenters expressed several concerns about the treatment of biomass-fired units 

in the proposed rule with respect to applicability. 

Commenters noted that the preamble of the proposed rule stated that applicability criteria would 

be the same under 111(d) regulations as applicability criteria for new fossil fuel-fired units; 

however, the proposed 111(d) rule fails to include the ten percent fossil fuel criterion. 

Commenters understood that units not primarily firing fossil fuels would be primarily firing 

biomass, and commenters objected to the proposal's failure to provide an exemption to certain 

biomass-fired units. Commenters urged the Agency to reconsider deleting the ten percent fossil 

fuel criterion, and to maintain consistency in applicability criteria across the various unit types 

and amongst all three proposed rules. Commenters opposed elimination of the ten percent fossil 

fuel exemption (included under the section 111(b) proposal) from the section 111(d) guidelines 

because commenters did not believe that the 111(d) proposal included any rationale for removal 

of this exemption. Commenters also stated that the description of this criteria for boilers and 

IGCC units in the preamble differed from the proposed regulatory text.

Commenters stated that CO2 emissions from facilities that burn biomass should be excluded 

from requirements for section 111(d) plans because such an exclusion will promote use of 

biomass and because operators that only burn a small portion of fossil fuel to facilitate use of 

biomass should not be burdened by compliance programs for section 111(d) plans. Commenters

stated that the proposal offered no justification for treating biomass-fired units the same fossilfuel-fired EGUs and commenters stated that the final section 111(d) rule not apply to units that 

get less than 10 percent of their heat input from fossil fuels, on a three-year average, consistent 

with the proposed section 111(b) standard for new units. Commenters stated that the final rule 

should exempt EGUs that primarily combust biomass and the final rule should clearly state that 

biomass is not a fossil fuel, and that replacing generation from an affected fossil fuel-fired EGU 

with generation from a biomass fuel-fired EGU is a valid compliance mechanism. 

Commenters stated that it is not appropriate to apply the section 111(d) guideline to EGUs that 

primarily burn biomass, and commenters believed the final rule should include an explicit 

exemption for such units. Commenters suggested use of the current subpart Da definition for 

"resource recovery unit" as one way to implement an exemption for biomass-fired units, and 

commenters recommended that the final guideline include an exemption from the CO2 standards 

for resource recovery units. Commenters also supported use of a three-year rolling average when 

determining whether an EGU is "fossil fuel-fired." Commenters stated that biogenic CO2 

emissions are distinct from fossil fuel CO2 emissions because biomass fuels are part of the 

natural carbon cycle and the carbon emitted from biomass-fired EGUs is rapidly cycled between 

atmospheric and terrestrial carbon pools. Commenters stated that there is no basis for EPA to 

eliminate the 10 percent fossil fuel threshold and expand these source categories to include 

biomass energy facilities in a final rule and that any such action would be premature because 

EPA is still in the process of developing a policy for how, if at all, it will account for biogenic 

CO2 emissions from stationary sources in regulations designed to reduce atmospheric GHG 

concentrations.
34

Commenters stated, the EPA's proposed changes to the applicability requirements for subpart Da 

units should not subject biomass units to regulation under CAA section 111(d).

Commenter stated, the EPA should conduct a separate rulemaking that addresses how biomass 

units will be regulated.

Commenters stated, all power plants should be included in the Rule. Commenters stated biomass 

incineration is not controlled at the level that it should be. Commenters stated in their

community, they have the Gainesville Renewable Energy Center that operates by burning woody 

biomass. Commenters said the CO2 released from this plant is 3 times more per kilowatt hour 

produced than the adjacent Deerhaven coal unit. Commenters concluded, any national policy 

should require more control of emissions from biomass incineration.

Commenters stated, the calculations and considerations reflected in the Proposed Rule must take 

into account the carbon dioxide emissions of all stationary sources generating electricity, 

including the burning of biomass, which can result in significant carbon emissions.

Commenters requested clarification of the definition of affected units with regard to the 

treatment of biomass-fired units.

Commenters asked "Can you please provide clarification specific to the definition of affected 

facility (new or existing)." Commenters quoted Federal Register / Vol. 79, No. 117 / Wednesday 

June 18, 2014 Proposed Rules under affected sources, on page 34854 section V.C, as stating "An 

affected EGU is any fossil fuel-fired EGU that was in operation or had commenced construction 

as of January 8, 2014, and is therefore an existing source for purposes of CAA Section 111, and 

that in all other respects would meet the applicability criteria for coverage under the proposed 

GHG standards for new fossil fuel-fired EGUs (79 FR 1430; January 8, 2014). Commenters 

noted that the January 8, 2014 proposed GHG standards for new EGUs generally define an 

affected EGU as any boiler, integrated gasification combined cycle (IGCC), or combustion 

turbine (in either simple cycle or combined cycle configuration) that (1) is capable of combusting 

at least 250 million Btu per hour; (2) combusts fossil fuel for more than 10 percent of its total 

annual heat input (stationary combustion turbines have an additional criteria that they combust 

over 90 percent natural gas); (3) sells the greater of 219,000 MWh per year and one-third of its 

potential electrical output to a utility distribution system; and (4) was not in operation or under 

construction as of January 8, 2014 (the date the proposed GHG standards of performance for new 

EGUs were published in the Federal Register). Commenters said the minimum fossil fuel 

consumption condition applies over any consecutive three-year period (or as long as the unit has 

been in operation, if less)." Commenters read Section 60.5795 and stated Section 60.5795(b)(1) 

does not make any reference to the 10% fossil fuel annual total BTU input found in the Federal 

Register / Vol. 79, No. 117 / Wednesday June 18, 2014 Proposed Rules under affected sources 

on page 34854. If paragraph (b) (1) is correct, commenters said a significant dilemma will be 

imposed on EGUs whose primary fuel source is biomass. Commenters said, for example, if the 

facility uses an oily rag to initiate combustion of the biomass in their furnace or warms the unit 

up using any type/amount of fossil fuel, the biomass EGU becomes subject to the rule. 

Commenters said this also presents a dilemma to a state as it will impair the state's ability to 

meet both their interim and final #CO2/MWh goals. Commenters stated many states that would 
35

rely on the energy generated from biomass as an attribute towards their CO2 reduction goals will 

now need to count the lbs/MWh of CO2 generated from biomass combustion against their goals.

Comment 2: Include entire electric power system.

Response 2: The EPA disagrees, the Clean Air Act does not provide the authority to regulate the 

electric power system but applies to individual stationary sources of air pollutants.

The following are summaries of the specific public comments under this comment:

Commenters believed that the applicability criteria for all of the final section 111 rules must be 

structured congruently to include renewable generating assets like wind turbines and solar panels 

because these assets are the key to reducing GHG emissions per MWh across the grid as a whole. 

Commenters suggested adding these renewable technologies to the scope of applicability as 

"unaffected EGUs." This will enable state programs that allow fossil fuel units to buy CO2 

credits from operators of renewable generating assets. 

Commenters supported the proposed view that the "source" (for the purposes of establishing the 

scope of applicability) is the entire electric power system, not just individual plant sites, because 

the bulk power system is a fully integrated installation of interconnected machines that all 

simultaneously deliver the same product. Commenters believed it would be inappropriate to limit 

applicability of a national CO2 per megawatt standard to only a portion of the interconnected 

installation that produces the CO2 and delivers the megawatts. Commenters cited a study by the 

Union of Concerned Scientists that indicated unrestricted national trading of renewable energy 

credits is a cost effective method for funding the expansion of renewable generating capacity if 

all generators that produce electricity for sale are included within the source category established 

under section 111.

Comment 3: Biomass units affected under the proposed rule.

Response 3: EPA agrees and has recategorized Hibbard as included in the CPP Final Rule 

baseline consistent with comment. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the biomass units at Minnesota Power's M L Hibbard station met the 

definition of affected units in 2012 and were mistakenly not included in Minnesota's affected 

units' inventory. Commenters said that the EPA incorrectly excluded the Hibbard units from its 

evaluation of affected units because they burn wood as a "primary fuel." Commenters stated even 

if the EPA finalizes rule language (referenced above) providing an exemption for steam 

generating units combusting fossil fuel for less than 10 percent of their heat input during any 

three consecutive years, the units at Hibbard would not meet such an exemption, and should 

therefore be included in Minnesota's inventory of affected units and considered in Minnesota's 
36

goal calculation. Commenters described the relevant units and said that they evaluated the 

characteristics of this facility in order to determine if the EGUs become subject to the rule under 

the proposed definition of an affected unit. Commenters said that even with a revised rule 

definition to allow up to 10 percent of fossil fuel for startup and combustion stabilization, 

commenters believed that fossil fuel emissions and generation for these units should be included 

in Minnesota's inventory of affected units, as they are burning fossil fuel in excess of the EPA's 

apparent intended exemption.

2.4 APPLICABILITY ISSUES RELATED TO COMBINED HEAT AND POWER (CHP)

This section addresses comments received on applicability issues related to combined heat and 

power (CHP) units.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Support for and opposition to inclusion of CHP and industrial CHP.

Response 1: As described See Section III.D.2 of the 111(b) final rule, the industrial CHP 

exemption has been significantly expanded and is based permit restrictions limiting the amount 

of electricity that can be sold. The final exemption is based on considering both the primary 

purpose and the environmental benefit of the unit. Therefore, the allowable sales is based on the 

design efficiency of the CHP unit. Specifically, the industrial CHP exemption is based on permit 

limiting annual electric sales to the unit’s design efficiency multiplied by its potential electric 

output or 219,000 MWh, whichever is greater. This limits applicability to CHP units that sell a 

significant percentages of the potential electric output. See section III.F.2 of the 111(b) final rule 

for a discussion of thermal output crediting. See section IV.D of the final rule preamble of the 

CPP for the EPA’s response to this comment. 

The following are summaries of the specific public comments under this comment:

Commenters were concerned about the impact on combined heat and power facilities. 

Commenters stated the 111(b) rule needs to be modified to avoid bringing industrial combined 

heat and power facilities into that rule, and this 111(d) rulemaking needs to reflect that as well.

Commenters stated that in AF&PA and AWC comments on the January 8, 2014 proposed NSPS 

for new EGUs and the June 18, 2014 proposed NSPS for modified and reconstructed EGUs, 

AF&PA and AWC explained the strong policy justifications for exempting industrial CHP units 

from the NSPS and from Section 111(d) guidelines. 

Commenters stated that CHP units are subject to numerous federal and state environmental 

regulations that would provide a check against unconstrained on-site emissions, including 
37

regulation of conventional pollutants under section 111 of the Clean Air Act and regulation of 

CO2 under the Prevention of Significant Deterioration ("PSD") program. Commenters stated that 

moreover, EPA retains authority to directly regulate industrial boilers and other categories of 

existing sources of CO2 emissions under section 111 sometime in the future if EPA determines 

that such emissions contribute to air pollution that endangers public health and welfare. 

Commenters stated that regulating CO2 emissions from industrial and institutional units in the 

context of a rule addressing utility EGUs would create significant complication and uncertainty 

if and when EPA issues rules specifically for CO2 emissions from those industrial and 

institutional units.

Commenters said that the most important way that the EPA can recognize the benefit of efficient 

CHP is to ensure that the applicability criteria for what is an "affected EGU" under the rule do 

not inadvertently sweep in industrial facilities that utilize CHP or WHP technology. Commenters

agreed that the EPA should provide clear guidance to the states that compliance should not 

impose regulations on CHP/WHP facilities. Commenters explained that while excess electricity 

may be supplied to the grid, industrial CHP units are designed for the purpose of producing 

useful thermal and electric energy for the facility itself and the associated thermal host. Because 

they are not intended to provide a majority of their energy output to the public power grid, 

commenters stated that they should not be regulated under this rule as commercial EGUs. 

Commenters added that the EPA should send a clear message to states that because compliance 

is measured with regard to the emission performance of affected EGUs, states should not force 

emission reductions from industrial CHP facilities that are not the kind of electricity generating 

units that are the subject of this rulemaking.

Commenters stated that strong policy justifications exist to exempt industrial CHP units from the

NSPS and Section 111(d) guidelines.

Commenters suggested that the EPA's role should be to help Maine and other states foster greater 

use of CHP technology. If requirements in a state's rules do end up being applied as part of the 

state's SIP to their units, commenters stated that their CHP units should be allowed to use 

alternative apportionment procedures as documented in a monitoring program meeting quality 

assurance requirements.

Commenters stated that the intent of the rule is to target the power sector, not to bring in 

unintended industries. Commenters stated that the final rule should be crafted to clearly and 

transparently articulate the sector targeted and should exempt industrial co-generation. 

Commenters stated that combined heat and power facilities capture and utilize heat that would 

otherwise be wasted from the production of electricity and therefore they require less fuel than 

an equivalent separate heat and power systems to produce the same amount of 

electricity. Commenters stated that by using less fuel CHPs reduce emissions of air pollutants 

and emit significantly less CO2 emissions than conventional boilers. 

Commenters stated that cogeneration units ("Cogens") should not be regulated as Electricity 

Generating Units under the CPP. Commenters stated Cogens are one of the least carbon intensive 

and most energy efficient ways to produce reliable electricity and useful heat, and to reduce 

electricity demand on the grid, with a consequent reduction in Greenhouse Gas emissions 

("GHG").
38

Commenters stated that EPA must fully recognize the benefits of combined heat and power in 

reducing GHG emissions in the energy sector. Commenters stated that combined heat and power 

facilities capture and utilize heat that would otherwise be wasted from the production of 

electricity; therefore they require less fuel than equivalent separate heat and power systems to 

produce the same amount of electricity and by using less fuel, CHPs reduce emissions of air 

pollutants and emit significantly less CO2 emissions than conventional boilers.

Commenters stated that the 111(b) rule needs to be finalized to avoid including industrial 

combined heat and power facilities at affected EGUs under that rule and this 111(d) rulemaking 

needs to reflect that as well.

Commenters requested that the EPA exempt combined heat and power (CHP) plants from 

applicability under the final rule and also requested that the final rule include the option for CHP 

plants to voluntarily opt into state compliance programs because these high-efficiency 

technologies are consistent with the Administrator's objectives under the proposed rule and 

commenters believed this policy will encourage future CHP projects. Commenters believed that 

an exclusion will reflect that industrial CHP units are fundamentally different from the fossil 

fuel-fired EGUs subject of this rulemaking because their primary purpose is not to provide 

electricity to the grid, and because these units are typically customized to suit the needs of the 

industrial host. Commenters stated that these variations among industrial CHP units make them 

particularly unsuitable for uniform nation-wide BSER analyses and makes calculation of thermal 

energy equivalence (conversion to kWh) impractical for reporting and enforcement purposes; 

commenters provided recommended regulatory text under section 60.5795 that would exempt 

CHP units and an alternative strategy for exclusion based on specific language for CHP units.

Commenters urged the EPA to utilize two principles for incorporating CHP into section 111 

rules: first, the rules should not inadvertently create disincentives to build or expand CHP; 

second, the rules should encourage expanded deployment of CHP technologies. Commenters

recommended that CHP facilities should not be explicitly regulated under the final rule, and 

commenters requested that the EPA ensure that CHP facilities are not inadvertently subject to 

regulation under the final rule. 

Commenters believed that exemption of CHP will promote expansion of CHP and supported 

complete exemption of CHP units. However, commenters acknowledged that the Agency may 

not provide such an exemption in the final rule, and commenters also offered a secondary 

alternative that the final rule should include an additional applicability criterion for determining 

which CHP units are affected EGUs; commenters stated that the final rule should include an 

exclusion for highly efficient CHP units (units achieving over 60 percent design system 

efficiency (HHV)) as an additional applicability criterion in order to encourage operators of 

existing fossil-fuel-fired EGUs to add CHP technologies. 

Commenters believed that the final federal guideline should explicitly state that installation of 

CHP technologies on existing EGUs is a federally approvable compliance strategy for state 

plans, but commenters did not believe that affected EGUs that install CHP for compliance 

purposes should become exempt.
39

Commenters supported an explicit exemption under the section 111(d) rule for combined heat 

and power (CHP) sources. Commenters also stated that if the final applicability provisions do not 

include an explicit exemption, then applicability should not include self-consumed power and 

applicability should only include power that is sold to the grid. Commenters stated that special 

credit under the rule is warranted for CHP sources because these sources are already combining 

two processes into an inherently efficient approach. In absence of a complete CHP exemption in 

the final rule, commenters believed the criteria for determining which CHP sources should be 

excluded from applicability are those sources that provide at least a 50 percent thermal energy to 

a host facility. Commenters also stated that the Agency should consider a 20 percent threshold 

consistent with the definition of net energy output, where units with at least 20 percent of the 

total gross energy output consists of useful thermal output on a rolling 3 year basis would not be 

considered an affected source.

Commenters argued that EPA should evaluate whether individual CHP units are affected sources 

subject to the 111(d) guidelines. Commenters explained that in addition to considering CHP 

facilities apart from NGCC units, EPA must also thoroughly assess whether the CHP units 

identified in the proposed rule even meet the definition of an affected source that is subject to the 

111(d) guidelines. Commenters stated that several examples have been identified in the building 

block two calculations of certain CHP units that clearly do not meet the definition of "affected 

sources" subject to the proposed rule. Commenters stated that EPA's criteria for determining 

affected sources in the proposed rule is summarized as follows: The EPA is proposing that, for 

the emission guidelines, an affected EGU is any fossil fuel-fired EGU that was in operation or 

had commenced construction as of January 8, 2014, and is therefore an "existing source" for 

purposes of CAA section 111, and that in all other respects would meet the applicability criteria 

for coverage under the proposed GHG standards for new fossil fuel-fired EGUs. (79 FR 1430; 

January 8, 2014). Commenters stated that the proposed 111(b) standards for new sources revised 

the "applicability criteria" in several ways for determining whether a facility is an affected 

source. Commenters said most relevant to combined heat and power facilities are revisions to (1) 

the averaging period used to assess applicability with the net electric output criterion, and (2) the 

exclusion of electric output consumed by the host industrial facility. Specifically, commenters 

noted that revisions in the averaging period are related to the applicability criteria that affected 

sources are those EGUs that are "constructed for the purpose of supplying more than 219,000 

MWh...Net-electrical output to the grid." Commenters stated, to evaluate this requirement, EPA 

notes that "We are also proposing to revise the averaging period for electric sales from an annual 

basis to a three-year rolling average for stationary combustion turbines." (27179 Fed. Reg. 1446. 

January 8, 2014. Commenters said, with respect to the definition of net electric output, EPA 

proposed adding the clause "of the thermal host facility or facilities." Commenters said, in 

describing the rationale for that revision, EPA notes: [O]ne potential issue that we have 

identified is inequitable applicability of third-party CHP developers compared to CHP facilities 

owned by the facility using the thermal output from the CHP facility. The current definition of 

net electric output...is "the gross electric sales to the utility power distribution system minus 

purchased power on a calendar year basis. Owners/operators of a CHP facility under common 

ownership as an adjacent facility using the thermal output from the CHP (i.e. the thermal host)

can subtract out power purchased by the adjacent facility on an annual basis when determining 

applicability. However, third-party CHP developers would not be able to benefit from the "minus 

purchased power on a calendar basis" provision in the definition of net electric output when 

determining applicability since the CHP facility and the thermal host(s) are not under common 
40

ownership. We are therefore proposing to....make applicability consistent for both facility-owned 

CHP and third-party owned CHP. Commenters remarked that the applicable definitions in the 

111(b) proposals for new sources and for modified and reconstructed sources incorporate these 

revisions. However, commenters noted that the 111(d) proposal selectively includes only the 

language related to using a three-year average. Commenters provided a comparison of the 

definitions in each proposal. Commenters asserted that the proposed 111(d) guidelines fail to 

mention EPA's concern of the "inequitable applicability of third-party CHP developers compared 

to CHP facilities owned by the facility using the thermal output from the CHP facility." Further, 

commenters said even though EPA included the "rolling 3 year basis" in the definition, nothing 

has been found in the docket to suggest that EPA actually performed an analysis of 3 year 

averages to determine the applicability of individual CHP facilities. Commenters said multiple 

CHP facilities have been identified that appear to have been erroneously included in the building 

block two calculations that otherwise would have been excluded had EPA properly considered 

all of the definitional revisions proposed in the 111(b) rulemakings. Commenters said, for 

example, EPA appears to have incorrectly included the Portside Energy CHP unit as an existing 

NGCC facility when performing the building block two calculations for the state of Indiana. 

Commenters noted that a review of the facility in context with how it is designed, where its 

located, and how its electric and thermal output is employed strongly suggests that the facility 

provides nearly all of its electricity to the "host facility" (not to a "utility distribution system"), 

and thus is not an affected source. Commenters mentioned a recent article about the facility 

noted that: Portside Energy's plant on the grounds of the U.S. Steel Midwest mill... provides 

most of the steel mill's electricity needs and all of its steam and hot water needs Commenters 

remarked that a sufficient number of similar examples were identified through a cursory review 

of other cogeneration facilities to suggest that the inclusion of CHP units within the building 

block two calculations for NGCC units is fundamentally flawed. Commenters said the end result 

is (1) that the 111(d) proposal is illegally applicable to a broader suite of sources than those that 

are subject to 111(b) new source standards; (2) EPA's building block two calculations 

inaccurately include cogeneration sources that are not affected sources subject to the proposed 

requirements; and (3) the corresponding state goal calculations, reliability assessments, and costbenefit analysis are derived from inaccurate data. Commenters posited that if EPA intended to 

identify affected sources under 111(d) "that in all other respects would meet the applicability 

criteria for coverage under the proposed [111(b)] standards," then EPA must adopt and apply that 

criteria in determining the applicability of existing co-generation units to the proposed rule. 

Further, commenters added, co-generation units are principally designed and operated to supply 

heat and power to a specific industrial or commercial process. Commenters concluded, stating 

that EPA must evaluate whether co-generation units could even be redispatched at higher 

capacity factors if such increased utilization would significantly impact or jeopardize the ability 

of units to achieve their primary objective of providing heat and power to a host process.

Commenters urged the EPA to ensure that CHP facilities are not inadvertently subject to 

regulation under this rule as "affected Electricity Generating Units," particularly excluding 

highly efficient CHP units that provide greater than 65 percent overall efficiency.

Commenters commented that the higher energy efficiency of CHP systems compared to separate 

heat and power systems (e.g., central power plant for electricity and onsite boiler for thermal 

needs) translates to fewer emissions associated with electricity produced from CHP systems, 

which leads to reduced emissions from EGUs when CHP systems are used onsite at industrial 
41

facilities. For this reason, commenters expressed support for considering industrial CHP systems 

as a potential approach to avoid affected EGU emissions and also supported considering CHP 

systems that lie outside of the industrial sector, for exactly the same reasons.

Commenters stated that CHP systems should not be categorized as affected units under the 

proposed rule. Commenters explained that industrial CHP facilities are used primarily for 

manufacturing applications to produce on-site electricity and thermal energy and are not intended 

to replicate the role of utility generators, but the applicability criteria for the proposed rule risks 

qualifying some industrial CHP units as affected entities that must be addressed in state plans. 

Commenters added that industrial CHP units further the intent of the proposed rule by providing 

efficient and less carbon-intensive electricity and thermal energy and also provide industrial 

market participants with an effective way to hedge electricity costs. Commenters stated that, to 

ensure that these facilities are not defined as affected units, and to remove potential disincentives 

for the use of industrial CHP, EPA should clarify that affected units do not include units that 

produce significant amounts of thermal energy.

Commenters requested that EPA clarify the status of industrial cogeneration units that use fossil 

and other fuels to generate retail electricity in the final rule's definition of affected EGU and 

modify the baseline accordingly. Commenters stated that EPA's proposed definition of affected 

EGU in the rule text, section 60.5795, is unclear on the treatment of industrial cogeneration 

operations that use coal and other fuels to produce electricity and process steam. Commenters

stated that the rule text can be read to include an industrial cogeneration as an affected facility. 

Commenters stated EPA included one NGCC industrial cogeneration facility in Washington in 

its listing of affected EGUs used for calculating the state goal. Commenters stated this unit has 

historically reported to CAMD as an affected plant for the Acid Rain Program. Conversely, 

commenters stated that the preamble and the spreadsheet determining affected EGUs indicate 

that industrial cogeneration units are not included in the rule, regardless of how much fossil fuel 

is used (unless the combustion units are natural gas combustion turbines). Commenters stated 

that this lack of clarity provides ambiguity for at least one Washington facility (a Weyerhaeuser 

facility located in Longview, Washington). Commenters stated that EPA's proposals under 

section 111(b) to amend subpart D and KKKK provide clarity on the status of these types of 

plants. Commenters stated that the proposed language for an affected EGU under this 111(d) 

proposal is not clear on the status of industrial cogeneration facilities that generate electricity for 

retail sale.

Commenters requested that EPA clarify the status of industrial cogeneration units that use fossil 

and other fuels to generate electricity for sale in the final rule's definition of affected EGUs. 

Commenters also requested that if this type of facility is included as an affected EGU, that these 

plants be included as cogeneration units with the baseline fossil emissions used to establish the 

final emission standards.

Commenters stated that the EPA is unclear in how Combined Heat and Power (CHP) facilities 

are treated and asked why the EPA didn’t provide clarity. Commenters asked when is a CHP 

facility considered "covered?" If this is determined by sales criteria, at what date is the 

determination made? Can this determination change? If so, under what criteria?
42

Comment 2: Thermal output credit for CHP.

Response 2: This final rule includes 100 percent credit for useful thermal output. See section 

III.F of the NSPS preamble for the EPA’s response to this comment. See section VIII.K of the 

final rule preamble of the CPP for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Comments regarding thermal Credit for Affected CHP Units

Commenters stated that EPA should give full credit for the thermal output of any CHP units EPA 

does regulate.

Commenters urged the EPA to count 100 percent of useful thermal output toward gross energy 

output. Commenters requested that the final rule include a clarification that the rule does not 

apply to CHP facilities that primarily produce thermal energy.

Commenters disagreed with EPA's proposal to allow only partial credit for thermal energy from 

CHP and advocated for 100 percent credit. Commenters stated that 100 percent credit is allowed 

in NSPS subpart KKKK for stationary combustion turbines. Commenters stated that the 

proposed requirement that limits CHP eligibility to systems with 20 percent gross useful energy 

output will alleviate any concerns about sham CHP projects. 

Commenters stated the EPA should allow facilities to include 100 percent of useful thermal 

output in calculating emission rates in order to be consistent with the treatment of useful thermal 

output in EPA's NSPS for combustion turbines in subpart KKKK; See 40 CFR 60.4420 (2014) 

(defining gross useful output as "For combined heat and power units, the gross useful work 

performed is the gross electrical or mechanical output plus the useful thermal output (i.e., 

thermal energy delivered to a process).”

In response to the request for comment on a range of two-thirds to 100 percent credit for useful 

thermal output from cogeneration plants and combined heat and power plants, commenters 

recommended that EPA allow full credit for useful thermal output towards compliance with the 

rule. Commenters recommended that EPA provide a compliance methodology that allows up to 

100 percent credit for useful thermal output from these facilities where it can be demonstrated. 

Commenters stated that several Wisconsin facilities, including West Campus and Whitewater 

NGCCs, provide useful thermal energy for heating/cooling or industrial processes. Commenters 

stated that such facilities should be provided the opportunity to demonstrate up to 100% use of 

the thermal energy.

Commenters contended that it would not be appropriate for EPA to specify best practices for 

measurement of useful thermal energy and quality assurance protocols, given the uncertainty in 

the proposal regarding the amount of credit that should be provided for whatever useful thermal 

energy is measured. Commenters argued that, since EPA is soliciting comment on allowing 

credit for 75 percent of measured thermal output, two-thirds or up to 100 percent, any gains that 

may be achieved in imposing additional measurement or quality assurance protocols would be 

lost in the noise of the policy assumption used to justify the final percent credit allowance.
43

Commenters applauded the EPA for acknowledging the emission reducing potential of putting 

thermal output to productive use when calculating the emission rate of an affected EGU. 

However, commenters stated that by only allowing states to count 75 percent of that useful 

output, the Clean Power Plan unnecessarily limits the incentive to add or expand CHP at existing 

EGUs. Instead, commenters recommended that the EPA should include 100 percent of useful 

thermal output when calculating affected EGU emission rates. 

Commenters recommended that 100 percent of the thermal output of affected EGUs should be 

credited under Section 111(d). Commenters stated that EPA has asked for comment on "a range 

of two-thirds to 100 percent credit for useful thermal output in the final rule to better align 

incentives with avoided emissions." Commenters stated that no rationale was provided for 

"discounting" thermal output relative to electric or mechanical output. Commenters stated that 

only accounting for a portion of thermal output undermines and distorts the true efficiency 

profile of a CHP system and as a result may encourage facilities to underuse thermal energy for 

non-electric generating uses even if such uses would be more efficient. Commenters stated that 

in practice, most CHP systems are designed for optimum efficiency based on the thermal 

requirements for the connected heating or cooling loads. Commenters stated that legitimate 

concerns regarding potential "sham" CHP projects can be fully addressed with appropriate 

monitoring and a minimum thermal output requirement.

Commenters stated that EPA should provide a full thermal credit for affected CHP units. 

Commenters stated that CHP's chief benefit is that it can produce heat and electricity from a 

single fuel source. Commenters stated that the proposed rule would credit all of the electricity 

produced from a CHP system, but only 75 percent of the useful thermal output. Commenters

noted that the EPA invited comment on "a range of two-thirds to 100 percent credit for useful 

thermal output in the final rule to better align incentives with avoided emissions." Commenters 

stated that to fully account for the benefits of CHP's EE, the rule should credit 100 percent of an 

affected facility's productively used CHP thermal output. 

Commenters stated that there is precedent supporting a 100-percent thermal credit. For instance, 

commenters noted that the EPA has recognized 100 percent of useful thermal output in the New 

Source Performance Standard (NSPS) for Stationary Combustion Turbines, and that a 100-

percent credit has likewise been applied in several states. Notably, commenters stated that the 

Proposed Stationary Combustion Turbine Rule favorably cites Texas' permit-by-rule regulation, 

which gives facilities 100-percent credit for steam generation thermal output.

Commenters stated that they understand that it may be appropriate to discount thermal output 

where there are concerns that the thermal energy is not being accurately measured or properly 

used, but stated that such concerns do not exist here. Commenters noted that the proposed rule 

includes strict monitoring requirements for CHP systems and these requirements should alleviate 

any concerns about so-called "sham" CHP projects. 

Commenters stated that this matter has important implications for state compliance plans. While 

only a handful of existing CHP and WHP systems are large enough to be directly affected by the 

CPP, commenters stated that the proposed rule offers states the flexibility to credit emission 

reductions from smaller units in their state plans. Commenters noted that states will look to

EPA's treatment of thermal output from affected units as a guide for the appropriate treatment of 
44

these systems in their compliance plans and underlying policies (e.g., portfolio standards). 

Absent proper consideration of their thermal output, commenters asserted that states will 

underestimate the emissions benefits of CHP units.

Commenters stated that full credit should be given for CHP (heat and mechanical energy). 

Commenters noted that EPA invites comments on a range of two-thirds to 100 percent credit for 

useful thermal output in the final rule (79 FR 34914). Commenters stated that the proposed rule 

would credit all of the electricity produced from a CHP system, but only 75 percent of the useful 

thermal output. Commenters stated that Maine's RGGI program now allows 100 percent credit 

for thermal output. 

For their units, commenters stated that the total gross energy output includes useful thermal 

output (steam), in addition to gross electric energy output. Commenters suggested that full 

thermal output credit for affected CHP units should continue to be allowed through a compliance 

demonstration (as is currently the case in Maine's regulations implementing RGGI). Without full 

energy output credit, commenters stated that CHP units would have no economic incentive to 

implement further measures to improve energy efficiency.

Commenters stated that thermal output can be monitored, measured, and recorded under a 

continuous monitoring program consistent with the requirements for monitoring electrical 

output. Commenters stated these non-billing meters can be included in a quality assurance, 

quality control program to produce accurate and reliable data. Commenters stated that thermal 

output is real and measurable, and it should not be discounted when included within an 

accounting framework for CO2.

In the case of EGUs or CHP units producing both electric energy output and useful thermal 

output, commenters stated that the apportionment procedure should include a thermal-to-electric 

energy conversion calculation (MMBtu steam/condensate to MW-h or MW-h electricity to 

MMBtus), and CO2 emissions should be allocated directly based on total output. For example, 

commenters noted that if electrical output is 60 percent of the unit's total output of useful energy, 

60 percent of the emitted CO2 should be allocated to electrical generation.

Commenters stated that the thermal energy (steam from process or heating) should also be 

acknowledged in the carbon rates applied to CHP units. 

Commenters stated that EPA must correct errors in its methodology for calculating useful 

thermal output from CHP units. Commenters stated that the proposed rule would credit all of the 

electricity produced by CHP systems, but only 75 percent of their useful thermal output. EPA 

invites comment on "a range of two-thirds to 100 percent credit for useful thermal output in the 

final rule to better align incentives with avoided emissions." While commenters were gratified to 

see this thermal credit in the proposed rule, they did not believe that thermal output should be 

discounted. Rather, commenters stated to properly account for the benefits of energy efficiency, 

the rule should credit 100 percent of a facility's useful thermal output.

Commenters continued that the characteristic that makes CHP both clean and efficient is its 

ability to produce both useful thermal and electric output simultaneously. Commenters stated the 

system's environmental benefits will only be recognized if both of these products are considered, 
45

and EPA recognizes this. Commenters stated that in a 2012 white paper on methods for 

calculating CO2 savings from a CHP system, EPA determined, "To calculate the fuel and CO2 

emissions savings of a CHP system, both electric and thermal outputs of the CHP system must 

be accounted for", and that for this reason, it is important to consider both thermal and electric 

output when determining an affected unit's emission rate. Commenters stated the proposed rule 

represents a good first step, but stops short of fully crediting system benefits. Commenters stated 

a 2005 EPA memo examining thermal credits explained that "giving between 75 to 100 percent 

thermal credit for thermal output from CHP units most accurately accounts for the environmental 

benefits of CHP." In the context of that rule (which addressed criteria pollutants, not CO2),

commenters stated EPA found that 75 percent was appropriate since it represented the average 

equivalent input-based emissions for the regulated pollutants (NOx, SO2 and PM) based on 

interpolating then current input-based New Source Performance Standards for industrial boilers 

and utility boilers.

Commenters stated that this rationale does not apply to this rule, which is regulating CO2. 

Further, commenters stated, unlike with criteria air pollutants, there are no National Ambient Air 

Quality Standards for CO2. Moreover, commenters stated the memo acknowledges that "one 

could also argue that 100 percent credit for thermal output is also appropriate." Commenters 

stated there is precedent supporting a 100-percent thermal credit. For instance, commenters 

stated EPA has recognized 100 percent of thermal output in the NSPS for Stationary Combustion 

Turbines. Commenters stated a 100-percent credit has likewise been applied in several states.

(EPA 2013) Notably, commenters stated, the Proposed Stationary Combustion Turbine Rule 

favorably cited Texas' permit-by-rule regulation, which gives facilities 100-percent credit for 

steam generation thermal output.

Commenters stated they understand that it may be appropriate to discount thermal output where 

there are concerns that the thermal energy is not being accurately measured or properly used, and 

that such concerns do not exist here. Commenters stated the proposed rule includes strict 

monitoring requirements for CHP systems. Commenters stated these requirements should help 

alleviate any concerns about so-called "sham" CHP projects. Commenters stated EPA also seeks 

comment on whether EGUs producing both electric energy output and useful thermal output 

should report both electric and useful thermal output. As explained above, commenters stated, 

these units should report both thermal and electric output, and that to do otherwise would 

minimize their measured and verified emissions benefits. Commenters stated this matter has 

important implications for state compliance plans. While only a handful of existing CHP systems 

are affected by the Carbon Guidelines, commenters stated the proposed rule offers states the 

flexibility to credit emission reductions from unaffected units in their compliance plans. 

Commenters said states may look to EPA's treatment of thermal output from affected units as a 

guide for the appropriate treatment of these systems in their compliance plans and underlying 

policies (e.g., portfolio standards). Commenters stated absent proper consideration of their 

thermal output, states will underestimate the emissions benefits of CHP units potentially leading 

to investments in other technologies, which may be more costly or less efficient or reliable in the 

long run. 

Commenters also mentioned that EPA's treatment of thermal output also has important policy 

implications beyond climate regulation. Congress is currently exploring options for 

comprehensive tax reform. Commenters stated in December 2013, the Senate Finance 
46

Committee released a draft energy tax reform proposal, which provided a "technology neutral tax 

credit" for all clean-energy technologies that are 25 percent cleaner than the grid average. 

Commenters stated given their carbon benefits, WHP and CHP should readily meet this testhowever, the proposal was limited to electrical output. Using this approach, commenters stated, 

CHP would not be eligible for favorable tax treatment. Commenters stated as tax reform moves 

forward, Congress will look to EPA for guidance. Commenters concluded that, by crediting 100 

percent of thermal output in the Carbon Guidelines, EPA sends a signal to Congress that it 

should do the same. Commenters stated EPA recognizes the relevance of such policy 

considerations. Commenters stated the proposed rule seeks comment on the appropriate thermal 

credit "to better align incentives with avoided emissions." as noted above, commenters stated the 

Administration has supported numerous policies to encourage greater CHP deployment. 

Commenters stated providing a full - 100 percent - thermal credit would place the Carbon 

Guidelines squarely in line with these broader deployment goals.

Commenters stated that EPA has asked for comment on "a range of two-thirds to 100 percent 

credit for useful thermal output in the final rule to better align incentives with avoided 

emissions." Commenters stated that no rationale was provided for "discounting" thermal output 

relative to electric or mechanical output. Commenters stated that only accounting for a portion of 

thermal output undermines and distorts the true efficiency profile of a CHP system and as a 

result may encourage facilities to underuse thermal energy for non-electric generating uses even 

if such uses would be more efficient and in practice, most CHP systems are designed for 

optimum efficiency based on the thermal requirements for the connected heating or cooling 

loads.

Commenters stated that a 2005 EPA memo, prepared during development of NSPS, explained 

that "giving between 75 to 100 percent thermal credit for thermal output from CHP units most 

accurately accounts for the environmental benefits of CHP." Commenters stated that in the 

context of that rule (which addressed criteria pollutants, not CO2), EPA found that 75 percent 

was appropriate since it represented the average equivalent input-based emissions for the 

regulated pollutants (NOx, SO2 and PM) based on interpolating then current input-based New 

Source Performance Standards for industrial boilers and utility boilers. Commenters stated that 

this rationale does not apply to this rule, which is regulating CO2 and further, the memo 

acknowledges that "one could also argue that 100 percent credit for thermal output is also 

appropriate."

Commenters stated that EPA has recognized 100 percent of thermal output in the NSPS for 

Stationary Combustion Turbines. Commenters stated that a 100 percent credit has likewise been 

applied in a number of states including California and Texas. Commenters stated that notably, 

the Proposed Stationary Combustion Turbine Rule favorably cited Texas' permit-by-rule 

regulation, which gives facilities 100 percent credit for steam generation thermal output. 

Commenters stated that legitimate concerns regarding potential "sham" CHP projects can be 

fully addressed with appropriate monitoring and a minimum thermal output requirement. 

Commenters recommended that 100 percent of the thermal output of affected EGUs be credited 

under Section 111(d).
47

Comment 3: Calculations involving useful thermal output.

Response 3: This final rule states that useful thermal output be measured relative to SATP 

conditions, See section V.C of the final rule preamble of the CPP for the EPA’s response to this 

comment.

The following are summaries of the specific public comments under this comment:

Commenters addressed calculations involving useful thermal output.

In comments to the Modified/Reconstructed Unit Proposed Rule, commenters made a number of 

recommendations regarding the extent to which the EPA permits facilities to account for useful 

thermal output and regarding the technical calculation of useful thermal output. 

Commenters stated that these recommendations are equally applicable to this proposed rule and 

should inform the EPA's definition of net energy output and useful thermal output in the final 

rule. Commenters included the following recommendations: 

• Useful thermal output should be defined relative to International Standard 

Organization temperature and pressure rather than Standard Ambient Temperature 

and Pressure in order to be consistent with all other CAA emission standards;

• Fuel drying should not be included in the definition of useful thermal output; and

• Thermal output for CHP units should be calculated based on the energy in the 

thermal output rather than based on the energy content of condensate return.

Comment 4: Net electrical output and purchased power for CHP.

Response 4: This final rule states net electric sales are used for applicability purposes because

that is a better indication of the intent of the unit than gross sales or generation. The intent of this 

final rule is to covers EGUs and not industrial units. See section III.F of the NSPS preamble for 

the EPA’s response to this comment. See section VIII.K of the final rule preamble of the CPP 

for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters opposed proposed changes to applicability criteria for CHP facilities under the 

111(d) proposal related to subtraction of purchased power when determining net-electrical output 

for applicability purposes.

Commenters stated that due to ambiguous language in the current Proposal, it may be possible 

for state programs to impose obligations on entities other than EGUs to meet their emission 

limits; however, in the preamble to the Proposal, EPA indicates that it intends the Section 111(d) 

state plans to address those types of EGUs that are currently subject to the 40 CFR Part 60 

Subparts Da and KKKK; and, will be covered in the proposed NSPS for GHG emissions from 

new, modified, and reconstructed EGUs. Commenters continued, stating that due to this 
48

inconsistency, the applicability provisions of the Proposal must be clarified to be consistent with 

CAA Section 111(d) and more importantly to reflect the past judgments EPA has made about the 

appropriate scope of facilities to be regulated as EGUs. Commenters explained that in the 

proposed NSPS for new EGUs and for modified and reconstructed EGUs, EPA addresses the 

simultaneous purchase and sale issue through the definition of "net-electric sales," similar to how 

it is dealt with in the existing NSPS. Commenters said, however, the Proposal does not contain a 

similar clear recognition that net-electric sales at a CHP unit for purposes of Section 111(d) 

applicability should be the net sales after subtracting out any purchases of electricity necessary to 

run the thermal host. Commenters asserted that there is no legal or practical basis for EPA not to 

treat the "cogeneration exclusion" any differently. Commenters believed EPA should include, in 

the applicability provisions of the final Section 111(d) guidelines, language similar to that in the 

definition of "net-electric sales" in the proposed NSPS for new EGUs. Commenters added that 

requiring state Section 111(d) plans to include cogeneration steam generating units (who provide 

less than one third of their net potential electric output and more than 219,000 MWH to the grid) 

is inconsistent with the thinking behind EPA's identification of Best System of Emissions 

Reduction (BSER). Commenters stated that EPA's system-based approach that looks to entities 

beyond the regulated facilities is not consistent with this past precedent, incompatible with the 

statutory provisions, and ultimately results in the regulation of a wide range of entities that are 

not existing sources subject to Section 111(d). Commenters closed, stating it essentially expands 

Section 111(d) plans beyond the types of units subject to the applicable NSPS, which is not a 

difference that CAA Section 111(d) allows. 

Comment 5: Transmission Line-Loss Credit for Affected Units.

Response 5: The final rule only covers CHP units exporting a significant portion of power. 

While it is not possible to calculate the exact savings we concluded that 5 percent is an 

appropriate approximation. 

The following are summaries of the specific public comments under this comment:

Commenters advocated that EPA clarify that line loss credits are allowed for both affected and 

unaffected CHP units, and that the 5 percent level of credit proposed by EPA should be 6 percent 

or more to better reflect average national T&D losses reported by EIA.

Commenters addressed line-loss credit for affected units which should reflect actual system 

losses. Commenters stated the proposed rule appears to include a five-percent line-loss credit for 

affected CHP systems. For CHP facilities, commenters stated, net energy output is defined as 

"the net electric or mechanical output from the affected facility divided by 0.95, plus 75 percent 

of the useful thermal output."

Commenters stated that there is no explanation for why output is "divided by 0.95"; however, the 

Carbon Pollution Guidelines for New Stationary Sources (111 (b)) explicitly provided a 5 

percent "line loss credit" for CHP systems "to account for a five percent avoided energy loss in 

the transmission of electricity." Commenters stated conversations with EPA staff confirm that 

this credit is likewise reflected in the instant proposal. Commenters commended EPA for 
49

including this credit in the rule, as avoided line losses are one of the key benefits of distributed 

energy generation. Commenters believed, however, that the proposed credit is inadequate. 

Commenters stated that on average, actual line losses from conventional generation are higher 

than 5 percent, and thus CHP projects that avoid such losses warrant a higher credit. 

Commenters stated the technical support documents accompanying the rule repeatedly refer to 

line losses of 7 percent or higher. For instance, commenters stated, as part of the BSER 

methodology for energy efficiency, EPA applies a transmission and distribution loss factor of 

7.51 percent. Commenters stated in the Technical Support Document for State Plan 

Considerations, EPA notes that national average line losses are 7 percent. Commenters stated the 

inconsistency between the technical support documents and the rule itself is inappropriate. 

Moreover, commenters stated line losses come at a significant economic cost, contributing to 

nearly $26 billion in foregone revenue in 2010 alone. Commenters stated these losses are even 

greater during peak hours. Commenters stated that in fact, a 2011 report by the Regulatory 

Assistance Project finds that a grid segment or area with average line losses of 7 percent could 

have marginal line losses of 20 percent during peak load. Commenters stated studies at Carnegie 

Mellon University and the Massachusetts Institute of Technology have shown that one 

megawatt-hour (MWh) of local generation, like CHP, can displace up to 1.47 MWh of central 

generation in some cases. Commenters stated these numbers imply the CHP benefit should be 

well above 5 percent where such lines-loss benefits exist. In the 111 (b) proposal, commenters 

stated EPA asserted that 5 percent "represents a reasonable average amount for the avoided 

transmission and distribution losses for CHP facilities."

Commenters stated that, in fact, a line-loss credit of 7 or 7.5 percent would be more 

"reasonable." Commenters stated that to do so, net electric output should be divided by 0.93. 

EPA should further clarify that the credit applies to both CHP and WHP. Commenters stated the 

proposed rule also provides that the apparent line-loss credit would apply whenever the useful 

thermal output is at least 20 percent of the total output. Commenters suggested that the rule add 

an efficiency standard to be consistent with the definition of qualifying CHP projects in the tax 

code. Commenters stated this will help counter any concerns that may exist about "sham" CHP 

projects. Lastly, commenters stated, the final rule should eliminate any ambiguity surrounding 

the line-loss credit, and that as written, this credit only applies to a subset of existing CHP 

systems that are directly affected by the rule. Commenters said states will consider EPA's 

approach, however, when determining how to account for output from CHP systems in their 

compliance plans. For this reason, commenters stated EPA should elaborate on CHP's 

transmission and distribution benefits and encourage states to apply a similar line-loss credit 

when accounting for CHP and WHP installations at unaffected units. Commenters stated these 

benefits are consistent with EPA's stated interest in enhancing electric reliability.

Notwithstanding their request for a CHP exemption under the 111(d) rule, commenters supported 

the proposal for modified and reconstructed units to apply a discount for avoided electricity 

losses through transmission and recommended that a discount of seven percent (based on EIA 

data) be incorporated into any final section 111(d) rule.

Commenters stated that EPA should adjust the compliance calculations to account for 7 or 7.5 

percent avoided transmission losses by the use of CHP.
50

Commenters added that if CHP is not recognized as a voluntary compliance measure, then the 

EPA should adjust the compliance calculations to account for 7 to 7.5 percent avoided 

transmission losses by the use of CHP. Commenters also stated that the EPA needs to ensure that 

the language of the CO2 Section 111(d) plan requirements for existing EGUs retains the current 

provisions that are designed to limit the application of EGU NSPS to CHP units.

Commenters stated that if the final rule does not include the requested exemption for industrial 

CHP units, the final rule should adjust the compliance calculations to account for 7 percent 

avoided transmission losses by the use of CHP.

Commenters supported the EPA proposal to allow CHP units an increase in produced electrical 

output to account for avoided transmission and distribution line losses. But rather than adopt a 

national average line loss credit, commenters advocated for use of average line losses for the 

state in which the CHP unit is located. Commenters pointed out that EIA currently has state-bystate line losses through 2012 (State Electricity Profiles, May 1, 2014). Commenters stated if 

EPA decides to adopt a single national line loss credit, the proposed 5 percent level is too low 

and suggested using 7.51 percent to be consistent with the line loss estimate that EPA used in 

calculating BSER in the Goal Computation TSD. Commenters recommended that the line loss 

credit be 6 percent or more to better reflect average national T&D losses reported by EIA and 

that EP should allow line loss credits for non-affected CHP units. Commenters stated that EPA 

has not explained why the net electric or mechanical output from the affected facility is divided 

by 0.95.

Comment 6: Upgrades to an existing unit to CHP.

Response 6: See section VIII.I of the final rule preamble of the CPP for the EPA’s response to 

this comment.

The following are summaries of the specific public comments under this comment:

Commenters requested that the EPA clarify the treatment of adding electric generation to 

existing fossil fueled boilers, incinerators, and industrial combustion units and use a more 

complex calculation for thermal output. Commenters stated that the EPA is unclear or silent on 

the value or treatment of adding electric generation to existing fossil fueled boilers, incinerators, 

and industrial combustion units. Specifically, on page 34924, commenters noted that the EPA 

requests comment on the use of industrial combined heat and power (CHP) units as a potential 

way to avoid EGU emissions and if the answer depends on the circumstances based on the type 

of CHP involved.

Commenters stated that the EPA, using its model of a CHP facility, has focused on fossil fuel 

fired electric generating units that also produce thermal energy. Commenters stated that this 

approach shows up in the discussion at 79 FR 34914 and in the discussions on state plan 

considerations and projecting EGU CO2. Commenters stated that this approach appears to match 

the reporting requirements in proposed 40 CFR 60.5805(c) but it is less clear whether this 

coordinates with the criteria to be an affected unit in 40 CFR 60.5795(b).
51

Commenters noted that the proposed definition of a CHP facility would exclude an existing 

industrial boiler or other combustion unit from consideration as an affected unit because it is not 

an electric generating unit. Commenters stated that this is in contrast to the lack of clarity in the 

criteria to be an affected unit in proposed 40 CFR 60.5795(b). Commenters stated the affected 

unit criteria appear to include any cogeneration facility, regardless of whether it was built as an 

EGU with the added benefit of using the waste heat from electricity production, or if it is an 

industrial cogeneration unit selling electricity. Commenters recommended that EPA make the 

criteria for an affected unit very clear to minimize future enforcement.

Comment 7: Voluntary opt-in for CHP.

Response 7: See section VIII.G of the final preamble of the CPP for the EPA’s response to this 

comment.

The following are summaries of the specific public comments under this comment:

Commenters requested that EPA state unequivocally that CHP units operating at industrial 

facilities will not be subject to federal requirements associated with the 111(d) rule, unless 

industrial CHP operators elect to opt in or otherwise voluntarily participate in carbon reduction 

programs established as part of a SIP or FIP.

Commenters stated that further, as discussed in AF&PA and AWC comments and in the 

comments filed by the NAM coalition on those proposed rules and the Section 111(d) Proposal, 

if the final rule allows for outside-the-fenceline compliance measures, EPA should explicitly 

recognize CHP as a voluntary compliance option under Section 111(d). 

Commenters stated that EPA should include industrial CHP as a resource in any Final Rule, and 

that CHP could create a meaningful way of meeting the stringent CO2 emission reduction 

requirements. Commenters stated that CHP facilities shouldn't be regulated under the CPP, but 

they should be recognized as potential contributors to carbon reduction goals on a voluntary 

basis. 

Commenters stated that to the extent that CHP units can reduce GHG emissions more efficiently 

than affected EGUS, CHP unit should be allowed to voluntarily "opt-in" to being covered under 

the 111(d) rule, so that they would not be within the scope of coverage of a future NSPS.

Commenters stated that if the final rule does not include the requested exemption for industrial 

CHP units, the final rule should explicitly recognize CHP as a voluntary compliance option 

under Section 111(d).

Commenters stated that the federal guidelines should use authority granted under CAA section 

111(b) (2) to establish a subcategory for CHP units to ensure state plans uniformly recognize the 

proven benefits of CHP technologies. Commenters stated that CHP facilities should be credited 

as a voluntary compliance solution, and the federal guideline should delineate how state plans 

can credit CHP facilities for their voluntary participation in meeting state goals. Commenters

believed that these measures can help ensure that reductions that have been provided over the 
52

years by existing CHP will be allowed to continue and commenters believed that CPP can drive 

significant expansion of CHP. Commenters believed that the final federal guidelines under 

section 111(d) should send a clear signal that the EPA will approve state plans that encourage the 

expansion of CHP as a means of reducing emissions from affected EGUs.

Commenters asked for clarification on treatment of industrial CHP units.

Commenters asserted that it is not EPA's intention to regulate industrial CHP units under this 

proposal, given the environmental benefits of CHP units and the government's affirmative steps 

to promote increased industrial distributed generation. While excess electricity may be supplied 

to the grid, commenters noted that industrial CHP units are designed for the purpose of 

producing useful thermal and electric energy for the facility itself and the associated thermal 

host. Commenters argued that because CHP units are not intended to provide a majority of their 

energy output to the public power grid they should not be regulated under this rule as 

commercial EGUs. Commenters stated that if EPA proceeds to finalize emissions guidelines for 

existing fossil fuel-fired EGUs, EPA should clearly ensure that the applicability criteria for 

affected sources exclude CHP units from the industrial and manufacturing sectors. Instead, 

commenters suggested that EPA permit industrial CHP units to participate voluntarily alongside 

other energy sources that can reduce net GHG emissions. Commenters stated such exclusion

would further incentivize the adoption and maintenance of efficient, reliable, and low-emission 

distributed generation.

Commenters supported the creation of a voluntary combined source category structure that is 

available for affected entities participating in an emissions market, as this would facilitate 

flexibility in compliance, including regional approaches and trading.

Commenters commented that, while not currently regulated, the EPA may consider regulating 

CO2 emissions from non-covered CHP sources because, in most cases, a facility installing CHP 

may increase onsite emissions while displacing a greater amount of emissions from the electric 

system. Commenters explained that the onsite increase could trigger additional or more-stringent 

regulation through other current or future rulemakings, and that this uncertainty could be a 

significant deterrent to facility owners considering new CHP. Commenters added that, if a 

facility anticipates future regulation, it may perceive a disincentive to participate in a Clean 

Power Plan emissions-reduction program in the near term, leaving readily deployable emissions 

reductions on the table. To address this issue, commenters proposed that the EPA should allow a 

non-covered CHP system to voluntarily place itself under current power plant regulation, either 

under section 111(b) (for new sources) or 111(d) (for existing sources). Commenters noted that, 

by placing the CHP system under regulation, direct emissions from the CHP system should be 

excluded from site emissions that may in the future be regulated by the Agency.

In response to the EPA request for comment "on whether industrial combined heat and power 

approaches warrant consideration as a potential way to avoid affected EGU emissions," 

commenters said that such systems should be recognized as a potential compliance tool for 

EGUs. Commenters added that references to "industrial CHP" ignore the significant potential for 

CHP in institutional and commercial sectors, particularly in systems serving universities, 

downtown areas, hospitals, military bases and other multi-building settings. 
53

Commenters recommended that applicability under the final rule should allow states to include 

CHP as a compliance measure. Commenters described five categories of CHP that should be 

creditable in state plans.

• Type 1. Existing power-only EGUs that meet the final 111(d) regulatory 

applicability criteria that are converted to a CHP technologies should receive 

credit for emission reductions in state plans; 

• Type 2. Existing CHP EGUs that meet the final 111(d) regulatory applicability 

criteria that increase utilization above baseline or that switch to lower carbon fuels 

should receive credit towards compliance in state plans;

• Type 3. Existing CHP EGUs that qualify for exemption (under the final 111(d) 

regulatory applicability criteria) that increase utilization above baseline should 

receive credit for emission reductions in state plans.

• Type 4. New CHP EGUs that meet the final 111(d) applicability criteria and the 

111(b) applicability criteria should be creditable in state plans under section 

111(d). 

• Type 5. New CHP EGUs that qualify for exemption (under the final 111(d) 

regulatory applicability criteria) should be creditable in state plans under section 

111(d).

Commenters noted inconsistencies in discussions of non-affected CHP units and suggested that 

EPA clarify in the final rule that emission reductions stemming from new and uprated CHP at 

non-affected units is an approvable compliance mechanism.

Commenters noted that, in a number of places, the Proposed Rule acknowledges the emission 

reduction opportunities from voluntary action by non-affected CHP and indicates that state plans 

that encourage that CHP would be approvable. ("[L]arge energy users might independently see 

additional energy efficiency opportunities or opportunities for self-generation using options such 

as combined heat and power, ... and states can structure their plans to allow the CO2 reductions 

achieved at affected EGUs through such actions to assist in reaching compliance."); ("States may 

choose measures that would ease pressures on system reliability. Commenters stated that this is 

true for many demand-side management approaches, including programs to encourage 

... combined heat and power, which actually reduce demand for centrally generated power and 

thus relieve pressure on the grid."). However, commenters noted that the Proposed Rule also 

contains language that suggests that non-affected CHP may not be an approvable compliance 

strategy. [Id. at 34924] ("The agency requests comment on whether industrial combined heat and 

power approaches warrant consideration as a potential way to avoid affected EGU emissions

..."). Commenters stated that this inconsistency has created significant uncertainty with regard to 

whether incremental generation from non-affected CHP will be deemed an acceptable 

compliance strategy by EPA. Commenters stated that such uncertainty will impact financing and 

investment decisions for new CHP and result in reluctance among states to include policies to 

encourage CHP in state plans. Commenters suggested that EPA eliminate this uncertainty by 

sending a clear signal in the final Clean Power Plan that policies to account for and encourage 
54

voluntary actions that result in new and uprated CHP at facilities other than affected EGUs are 

approvable compliance tools in state plans.

Commenters asked for clarification on treatment of CHP units with respect to the definition of 

"affected EGU."

Commenters acknowledged that EPA's definition of "affected EGU" does not, itself, determine 

whether a state will incorporate that unit into its compliance plan as an "affected entity." 

However, commenters stated that the Clean Power Plan does propose to require states to address

all affected EGUs. [79 FR 34954, proposing Section 60.5795(a)] Commenters stated it is 

important that EPA provide states with sufficient flexibility to adopt policies that do not impose 

obstacles to existing CHP usage and that encourage new CHP at affected EGUs and other 

entities. 

Commenters primarily recommended that EPA determine that CHP facilities are not "affected 

EGUs," and that EPA should also make clear to the states that they need not mandate reductions 

of emissions at any CHP facilities in their compliance plans. However, commenters stated that if 

EPA insists on using the same applicability criteria for all three Section 111 rules, which 

potentially could make some CHP facilities into "affected EGUs," then commenters urged EPA 

to adopt its recommendations with respect to those criteria. By adopting the applicability criteria 

that commenters have recommended in comments on the associated Section 111 rulemakingsincluding an exclusion for highly efficient CHP, commenters noted that EPA can provide states 

with that needed flexibility. In any event, commenters stated that EPA should make clear to 

states that if a unit is not an affected EGU, the unit's emissions will not factor into the "emission 

performance" of "affected EGUs" in the state.

Commenters stated that nothing in EPA's rule should preclude the State of Maine from 

preserving the incentive for CO2 budget units that are combined heat and power (CHP) units at 

integrated manufacturing facilities. Commenters asserted that Maine should continue to promote 

and reward the operation of RGGI CO2 budget units that are CHP producers at integrated 

manufacturing facilities by using the CO2 allowances to offset behind-the-meter CO2 emissions. 

Commenters added that "Behind-the-meter CO2 emissions" means the difference between the 

total annual CO2 emissions from a CO2 budget unit that is a combined heat and power unit at an 

Integrated manufacturing facility and the annual CO2 emissions associated with the 

net electricity that is transmitted over the facilities of a Transmission and distribution utility from 

such a unit.

2.5 DEFINITION OF AFFECTED SOURCE

This section addresses comments received regarding the definition of affected source.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.
55

Comment 1: Ambiguity in the definition of affected source.

Response 1: The final rule clarifies that the only affected entities subject to regulation under 

111(d) are those meeting the definition of affected EGUs. Non-EGUs are not affected sources.

The following are summaries of the specific public comments under this comment:

Commenters stated and concurred that EPA's proposed rule does not provide sufficient notice as 

to what entities may be included as affected entities, explaining that the plan EPA relies on 

affected entities, a category defined simply as an "entity with obligations under this subpart for 

the purpose of meeting the emissions performance goal requirements in these emission 

guidelines." Commenters continued, (verbatim) affected entities have enforceable duties, duties 

that in some way reduce electric generation from existing fossil units, thereby reducing CO2 

emissions from affected EGUs. Commenters said EPA notes in the preamble and in numerous 

TSDs that various entities may take actions that reflect reductions in affected EGU emissions. 

Commenters said, however, EPA's definition of affected entities, while broad, is tied to the 

"enforcing measures" provision, Section 60.5780, which creates ambiguities as to what is or is 

not an acceptable affected entity. Further, commenters noted that the vague language does not 

adequately anticipate certain categories of projects that will occur. Commenters’ examples are 

described below. Commenters stated, by not specifying in the rule itself the type of projects that 

EPA would and would not accept - as detailed in the rule's accompanying documents - the rule 

itself creates ambiguity and fails to provide the flexibility that EPA wants and the certainty that 

states and sources require, opening up both the states and sources to unwarranted lawsuits. 

Commenters said, for example, EPA appears to allow new fossil-fuel fired entities, with lower 

carbon intensity than affected EGUs, to be used for compliance. Commenters noted that these 

units would be built according to a Section 111(b) standard and be "exempt" from the affected 

EGU category. See Proposed 60 C.F.R. section 5800, 79 Fed. Reg. 34,954. Commenters stated 

that such a new or modified unit likely would replace an existing, higher intensity unit, or reduce 

output from an existing higher intensity unit. However, by not specifically listing replacement 

EGUs as affected entities and specifically exempting them from the affected EGU category, 

commenters asserted that EPA creates an impermissible ambiguity as to whether such units can 

be affected entities and whether they can be accounted for in meeting state goals. 

Commenters stated EPA defines EGU elsewhere in the EPA proposal but does not specify 

whether or not the owner of an EGU would count as an affected entity or an affected source for 

purposes of the definition of "emission standard." Commenters said an open question is whether 

or not a state could tax an owner of an EGU as an "affected entity" based upon fuel purchases for 

or emissions from "affected sources" that it owns. Given the significance of the interaction 

between the definition of affected EGU or source and other affected entities, commenters 

suggested that EPA should consider clarifying its view of these terms. See EPA, Carbon 

Pollution Plan for Existing Stationary Sources: Electric Utility Generating Units, 79 Fed. Reg., 

34954; 34956. 
56

Comment 2: Support for and opposition to inclusion of small-sized units and cooperatives.

Response 2: The EPA does not prescribe how a state must meet the emission guidelines. That 

is, the emission guidelines do not require that small electric cooperatives or small municipal 

power systems bear compliance burden. CAA section 111(d) creates a partnership between the 

EPA and the states under which the EPA establishes emission guidelines and the states take the 

lead on meeting them by creating plans that are consistent with the EPA emission guidelines. 

The final rule establishes the BSER specifically for affected sources in the form of subcategoryspecific performance rates for affected EGUs instead of only setting goals for a state. Each state 

will determine whether to impose source-by-source limitations reflecting the BSER performance 

rates to each affected EGU or to adopt a state measures approach and meet either an equivalent 

statewide rate-based goal or statewide mass-based goal. A state choosing the state measures 

approach will have the option to place few or no requirements directly on affected EGUs. 

Specifically, the final guidelines are structured so that states are not required to use each and 

every one of the measures that the EPA determines constitute the BSER or to apply any one of 

those measures to the same extent that the EPA determines is achievable at reasonable cost on a 

national basis. Instead, in developing its plan, each state will have the flexibility to select the 

measure or combination of measures it prefers in order to achieve the CO2 performance rates for 

its affected EGUs or meet the equivalent statewide mass-based CO2 goal. 

The EPA recognizes that each state has differing policy considerations – including varying 

emission reduction opportunities and existing state programs and measures – and that the 

characteristics of the electricity system in each state (e.g., utility regulatory structure, generation 

mix and electricity demand) also differ. The final rule gives states the flexibility to implement a 

broad range of approaches that recognize that the power sector is made up of a diverse range of 

companies that own and operate fossil fuel-fired EGUs, including vertically integrated 

companies in regulated markets, independent power producers, rural cooperatives and 

municipally-owned utilities, all of which are likely to have different ranges of opportunities to 

reduce GHG emissions while facing different challenges in meeting these reductions. By 

expressing the application of the final BSER as a source-specific performance standard, and by 

providing a translation of that to statewide rate- and mass-based CO2 goals based on each state’s 

particular mix of sources, the rule allows states the flexibility to determine how to achieve the 

CO2 reductions (i.e., greater reductions from one building block and less from another, as well as 

the adoption of other measures that lower carbon intensity), and to adjust the timing in which 

reductions are achieved, in order to address key issues such as cost to consumers, electricity 

system reliability and the remaining useful life of existing generation assets.

The following are summaries of the specific public comments under this comment:

Commenters suggested that the EPA include additional guidance for state plans regarding 

enforceability of requirements that apply to EGUs that are not large enough to meet Title V 

thresholds because states should be allowed to include smaller EGUs in their plan to implement 

section 111(d) as long as the state-level overall goal is met.

Commenters, small electric cooperatives in Colorado, urged the EPA to consider specific 

waivers or considerations that recognize cooperatives have smaller generating fleets and less 

flexibility than large investor owned utilities because Colorado's electric co-ops are not vertically 
57

integrated; this means that separate power companies generate and transmit (on high voltage 

lines to substations) the electric power ultimately distributed (from the substations) to the 

member-customers of the cooperatives on the cooperative's low voltage lines. Commenters

believed this vertical "disaggregation" distinguishes electric co-ops from investor-owned and 

municipally owned utilities because no electric distribution cooperative in Colorado owns 

enough generation capacity to supply its members' electric demands, and cooperatives must rely 

on long term all requirements contracts with wholesale suppliers for most if not all of their 

electric capacity. Commenters were concerned that increased regulatory costs to the wholesale 

suppliers will necessarily be passed on to the distribution co-ops and negatively impacting the 

co-ops' ability to provide reliable electric service at a reasonable rate. Commenters also believed

the proposal will result in the EPA usurping the authority of locally-elected co-op boards, 

working with their wholesale power suppliers, to determine the appropriate power supply mix in 

their states. Commenters also believed that the EPA should consider giving greater credit for the 

emission reductions Colorado cooperatives have achieved prior to the proposed 2012 baseline 

year, and commenters requested that EPA allow states to include all reduced-carbon technologies 

in their section 111(d) state plans including additional resources that have the net effect of 

reducing greenhouse gas emissions.

Commenters stated that the proposal did not adequately address the differences between large 

utilities and smaller utilities such as cooperatives, and commenters believed the proposed rule 

disproportionately impacts smaller utilities with less generation, less diverse fleets, and 

electricity consumers with fewer financial resources. Commenters believed that these differences 

make achieving the proposed standard much more difficult for smaller utilities. Commenters

stated that since many of these smaller utilities do not serve retail customers directly, it will be 

difficult to implement the beyond-the-fence energy efficiency measures. Commenters stated that 

many cooperatives serve rural, impoverished counties, with mostly residential customers located 

in service territories where investor owned utilities have declined to provide services because the 

low density of electricity customers is not sufficiently profitable for their investors. Commenters

provided Georgia as an example where 90 percent of cooperative customers are residential and 

many of those residential customers struggle to pay ever-increasing power bills. Commenters

stated that many cooperatives operate as not-for-profits and are required to minimize operational 

costs yet fulfill their obligation to deliver electricity, regardless of the demand imposed on their 

system. Commenters stated the propose rule is unprecedented because it will affect every aspect 

of the way electricity is generated, transmitted, distributed and sold nationwide and will 

disproportionally impact impoverished users of electricity. Commenters stated that cooperatives 

will have no choice but to pass on to impoverished customers the increased costs of service, 

unlike larger systems that can spread such costs over a larger, more diverse (and more affluent) 

customer base. Commenters requested that the final federal guideline allow states to include 

conditional exemptions for small not-for-profit municipal utilities because these utilities operate 

under different regulatory structures with different financial constraints than the vast majority of 

the electric utility sector, and commenters believed that states will need the flexibility to develop 

plans with differing levels of requirements tailored to specific utility models. Commenters stated 

that several aspects of the proposed federal guideline will have significant impact on small 

municipal utilities and that certain small municipal utilities who own and operate new clean 

EGUs, like Dallman Unit 4, should be treated separately under state plans. Without provisions 

for a separate program or conditional exemption for financially constrained utilities, commenters
58

believed the federal guideline could have devastating impact on the small municipal utilities, 

cooperatives and customers. 

Commenters, operators of rural electric cooperatives serving economically disadvantaged 

citizens, stated that the final rule must incorporate opportunities for addressing problems and 

issues that are distinct and specific to rural electric cooperatives because 40 CFR 60.24(f) 

requires federal guidelines to allow states to consider other factors specific to the facility (or 

class of facilities) that make application of a less stringent standard or final compliance time 

significantly more reasonable. Commenters stated that the lbs. /MWh reduction goals in the 

proposal create insurmountable problems for rural electric cooperatives because rural electric 

cooperatives typically have limited generation portfolios and rely heavily on coal-fired 

generation for a predictable, deliverable, and low-cost fuel. Commenters stated that rural 

cooperatives also face unique financing constraints with lender arrangements that place rural 

electric cooperatives at a higher risk of stranding assets. Commenters stated that rural 

cooperatives typically have a minority share of EGU ownership (and associated leverage on 

planning decisions).Commenters stated that rural electric cooperatives generally serve parts of 

the state that are more economically disadvantaged and more sensitive to rate increases that 

follow state and federal mandates that render partially depreciated investments in existing 

generating assets un-usable, and that require investments in new generating assets (both of which 

must be re-paid by members). Commenters stated that a cooperative has limited ability to 

achieve emissions reductions through demand-side energy efficiency measures, and commenters

served members that live in two different regional transmission organizations; commenters stated 

that these constraints are significant administrative and operational challenges for compliance. 

Commenters believed that the compliance challenges faced by rural electric cooperatives are the 

reason Congress mandated that the federal guideline permit the states to consider other factors 

when the state applies a standard of performance to an existing source that has come under 

federal regulation pursuant to CAA section 111(d).

Commenters stated that CAA section 111(d)(1) and 40 CFR 60.24 direct EPA to provide states 

with broad flexibility to determine the extent to which to apply standards of performance to 

particular sources and source categories. Commenters believed that this flexibility is particularly 

important for cooperatives and small utilities, which will face significant challenges in 

complying with any standard of performance based on the BSER that EPA has proposed. 

Commenters stated that preamble text acknowledges the plight of many rural electric 

cooperatives with very small fleets and few options for compliance in competitive power 

markets, but commenters stated that the federally predetermined goals fail to give states the 

flexibility necessary to address the challenges facing rural electric cooperatives. Commenters

stated that the proposed statewide emission reduction targets are based on unfounded 

assumptions about the availability of re-dispatch, renewables, and demand reduction, and 

commenters asserted that the proposed rule had no provisions for adjusting proposed targets if 

the underlying assumptions prove to be inconsistent with reliable and affordable service when 

applied to certain rural regions of the electricity grid. Commenters believed that the proposed 

rule is unlawful because the proposed state goals deprive the states of permissions granted to the 

states by Congress (under CAA section 111(d)(1)) to apply standards to rural cooperatives in a 

reasonable way. Commenters believed that the Act mandates that the final federal guidelines 

must permit states to consider individual unit circumstances, including remaining unit useful life

when the state applies section 111(d) standards to existing sources. Commenters stated that the 
59

final federal guidelines should recognize that: (1) most rural electric cooperatives have extremely 

limited portfolios of generating assets and therefore that re-dispatch to gas-fired or renewable 

energy sources may not be available for many rural electric systems; (2) in many cases they rely 

on coal-fired EGUs that may be able to make only minimal improvements in heat rate to achieve 

lower CO2 emission rates; (3) existing lessor financing arrangements and concerns about 

creating stranded assets through premature shutdown or curtailment would create significant 

adverse rate impacts for small rural electric cooperative members, and these existing debts will 

constrain the ability of cooperatives to incur additional investments for technologies that can 

comply with the proposed standard; and (4) opportunities for additional demand-side energy 

efficiency measures in rural areas are likely to be extremely limited due to the rural and largely 

residential nature of the membership. Commenters stated that the suggestion in the preamble that 

cooperatives build or contract for electric supply from lower-emitting sources is unlikely to be 

practicable and will result in unreliable electric supply to rural customers at extraordinary rates. 

Commenters stated that many small investor-owned utilities also face the same challenges 

caused by limited generation portfolio, coal reliance, and widely dispersed, largely residential 

customers.

Commenters believed that the final rule can solve the problems proposed for small cooperatives 

and small utilities by strictly following the statutory mandate and by finalizing a federal 

guideline that permits the states to consider all factors relevant to establishing a state goal and 

subsequently applying the corresponding standards that reflect these factors and the remaining 

useful lives of the affected EGUs. Commenters urged the EPA to limit itself to its statutorily 

prescribed roles of: (1) defining the procedures under which the States will develop and submit 

their plans, and (2) identifying the best system of emission reduction that EPA determines has 

been adequately demonstrated.

Commenters stated that the extraordinary challenges and obstacles rural electric cooperatives 

(and other small utilities) would face in attempting to comply with the proposed emission 

guidelines demonstrate the need for state discretion to take these and other relevant 

considerations into account in determining the extent to which any standard of performance can 

be applied to cooperative-owned units, whether individually or as a class. 

Commenters did not believe the proposal adequately addressed the differences between large 

utilities and smaller utilities like cooperatives. Commenters, not-for-profit municipal utilities

whose "affected units" emit less than 2.6 percent of Illinois' total EGU emissions, indicated that 

state environmental and electricity regulations recognize the differences between not-for-profit 

cooperatives and investor owned utilities because they are exempt from the jurisdiction of the 

state's public utilities commission and also exempt from the state Renewable Portfolio Standard 

(RPS) established by state statute which is likely to be a major component of Illinois' section 

111(d) plan. Commenters emphasized that many Americans that depend on cooperatives to 

deliver their electricity are below the poverty line and commenters provided statistics for two 

counties within her cooperative's service territory where more than 40 percent of the electricity 

consumers were below the poverty line.

Commenters, investor owned utilities, opposed special treatment of small municipally owned 

utilities and cooperatives because commenters believed that all load serving entities in a state 

should be subject to similar requirements in order to prevent placing undue hardships on 
60

investor-owned utilities. Commenters recommended that the final guideline not include 

provisions for special treatment of rural cooperatives and small municipal utilities, but also stated 

that if the final guidelines do include such provisions, the final guidelines should also adjust 

state targets. Commenters stated that her utility operates five EGUs that are partially owned 

by several municipal utilities or rural electric cooperatives, and commenters stated that joint 

ownership in a large generating unit is often a low-cost way for smaller utilities to provide load 

to their customers without the significant investment costs associated with constructing, 

operating and maintaining individual generating resources. Commenters stated that ownership 

rights and responsibilities, including environmental compliance obligations, are governed by 

joint-ownership agreements, and commenters opposed creating special classes of utilities in the 

final rule because commenters believed segregation into special classes will interfere with 

existing, contractual, joint-owner relationships. Commenters believed the states are in a better 

position to decide on requirements for different types of utility companies than the federal 

government. Commenters, utilities operator serving customers that live at or below the poverty 

line, believed that a comprehensive climate policy must include protection for low-income 

customers from the economic impact of such regulation, for instance through an increase in 

earned income tax credits or through a rebate refund program.

Commenters stated they are the only municipal utility with generation in Illinois. Commenters

requested the USEPA adjust its GHG Rule to provide guidance to states for the provision for 

small not-for-profit municipal utilities like CWLP, which meet the unique factors that distinguish 

them from other affected entities subject to the plan. Commenters explained that such guidance 

should expressly allow for states to consider the following options in state plans that the EPA 

would deem compliant with the CPP (verbatim): 1. Conditional Exemption: A state plan should 

be authorized to conditionally exempt a utility or unit based on specific findings at the state level 

that the integration of the utility or the unit would cause disproportionate financial hardship 

while not substantively aiding the state in meeting the goals of the CPP. 2. Subcategorization: 

Given EPA's novel approach to interpreting the entire electric system as the Best System of 

Emission Reductions (BSER), the EPA should expressly clarify the ability of a state to 

subcategorize by utility type to better reflect the obligations that will accrue to each utility based 

on the assets it owns, its ownership structure, the authority of the state EPA to require actions, 

and how it engages in electric markets. 3. Alternative Compliance Mechanisms: EPA should 

expressly clarify that states may establish more than one compliance option with in a state such 

that utilities with different ownership structures, assets and obligations may choose to aid the 

state in meeting its obligations to comply with the CPP in the most efficient manner possible. 

Commenters recognized that the proposed rule allows a state to demonstrate "equivalency" using 

several tests. Commenters said, for example, the EPA specifically recognizes RPS as the type of 

state policy or program through which the GHG rule is "building on actions already underway in 

states and the power sector." (At 34848.) Yet commenters believed the RPS examples given 

from other states or utilities are well below the 20% they have already achieved and is achieving 

at greater cost than estimated by EPA. Commenters stated, similarly, the savings of Arizona 

investor-owned utilities are far below those achieved by commenters through its own EE 

programs. Commenters' carbon intensity equation meets or exceeds what the U.S. EPA expects a 

utility or unit to achieve as a result of the GHG Rule. Commenters stated that for these reasons, 

they requested the U.S. EPA add to its equivalency options a state's authority to differentiate 

units or utilities through one of the mechanisms above.
61

Commenters argued that EPA should make clear that states should take into account the 

challenges of small public power systems and units. Commenters also argued that EPA should 

provide flexibility for states to address municipal utility challenges.

Comment 3: Allow small units to opt-in.

Response 3: The EPA does not agree. Reduction in emissions from small power plants not 

covered by the rule and not connected to the grid do not result in emission reduction at affected 

EGUs and therefore cannot be used to meet the emission reduction requirements for affect 

EGUs. 

The following are summaries of the specific public comments under this comment:

Commenters suggested that the final rule include applicability provisions that would allow 

sources that are otherwise below applicability thresholds or that are otherwise unaffected be 

allowed to opt-in to the pool of sources that are subject to section 111 standards because this 

would enable states to encourage the operators of otherwise uncovered power plants to earn 

some type of credit by reducing emissions; for example, small, diesel generators in rural Alaska 

are not covered by the proposal since they are small and not connected to the state's electrical 

grid; however, some of these generators could be replaced by cleaner sources, such as small runof-the-river hydroelectric projects.

Comment 4: Commenters provide rationales to support or oppose the combination of source 

categories into a single new subpart UUUU. 

Response 4: In this rule, the EPA is combining the steam generator and combustion turbine 

categories into a single category of fossil fuel-fired electricity generating units for purposes of 

promulgating emission guidelines for GHG emissions for existing sources. Combining the two 

categories is reasonable because they both provide the same product: electricity services. 

Moreover, combining them in this rule is consistent with our decision to combine them in the 

CAA section 111(b) rule for new, modified and reconstructed sources that accompanies this rule. 

In addition, many of the monitoring, reporting, and verification requirements are the same for 

both source categories, and, as discussed next, we are codifying all requirements in a single new 

subpart UUUU of the regulations; as a result, combining the two categories into a single category 

will reduce confusion. It should be noted that in this rule, we are not combining the two 

categories for purposes of standards of performance for other air pollutants. EPA also notes that 

the affected unit for this final rule is a single combustion turbine engine and any associated heat 

recovery steam generator. The EPA notes that for 111(b) purposes, the definition of the affected 

facility is often defined as a single source of emissions. We may consider expanding the 

definition of the affected facility in future rulemakings.

The following are summaries of the specific public comments under this comment:
62

Commenters stated that EPA's proposal to combine two existing categories could be 

accommodated by allowing this approach in a state plan as provided flexibility, but without 

making it mandatory. Commenters explained that this approach would allow shifting or dispatch 

of resources within a system or category treated as a system: e.g., municipal electric utilities 

within a state. Commenters did not object to combining the categories, but questions how this 

could affect state goals, noting that state energy supplies from steam EGUs and combustion 

turbines are not homogenous among these two categories and vary even further from state to 

state. Commenters believed that if the USEPA allows the states full flexibility, then the state 

would be able to decide how to average emissions from these two categories in order to meet the 

required emission goals.

Commenters stated that in Subpart KKKK, when two stationary combustion turbines with heat 

recovery steam generators supply a common steam turbine and steam turbine electric generator, 

EPA should enable applicability and compliance for the two combustion turbines to be 

determined on a combined basis. Commenters explained that a very common current design for a 

combined cycle facility is to use two (or more) stationary combustion turbines, each with a 

combustion turbine electric generator, and each with a heat recovery steam generator (HRSG) 

that may include a duct burner - with the steam from each HRSG directed to a common steam 

turbine and steam turbine electric generator. Commenters noted the design using two stationary 

combustion turbines is commonly called a "two-on-one" or "2X1" configuration. Commenters

believed that EPA should provide an option, at the election of the owner/operator, for facility 

designs such as the "2X1" configuration to determine applicability and to comply on a combined 

basis rather than by a combustion turbine by combustion turbine basis. Commenters explained 

that for "2X1" compliance, carbon dioxide emissions from both combustion turbines (and any 

duct burners) would be combined to determine total emissions. Commenters noted that gross 

MWH from the two combustion turbine electric generators and the common steam turbine 

electric generator would be combined to determine total gross MWH, and this option would 

remove the need to apportion gross MWH produced by the steam turbine electric generator to 

separate combustion turbines as proposed under rule section 60.4373(e). Commenters stated that 

compliance would be determined using the total CO2 emissions divided by the total gross MWH. 

Commenters stated that applicability criteria for a "2X1" configuration under proposed rule 

section 60.4305 would likewise be determined on a combined basis, doubling the actual electric 

output applicability threshold to reflect two combustion turbines.

Commenters stated they support the use of flexible compliance measures under 111(d), adding 

that if EPA concludes that combining the two existing source categories (fossil steam EGUs [Da] 

and combustion turbines [GG/KKKK]) into a single subpart (TTTT) for purposes of regulating 

existing sources under 111(d) would facilitate such flexibility, Commenters would support such 

a regulatory structure.

Commenters stated they support consolidating the two source categories of affected EGUs 

covered by the emission guidelines - electric steam generating units and combustion turbines -

into one regulated source category for purposes of establishing carbon pollution standards for all 

EGUs, including the emission guidelines for existing EGUs as well as the performance standards 

for new, modified, and reconstructed EGUs. Commenters explained a consolidated source 

category would reflect the identical market functions served by all of the affected EGUs covered 

by EPA's proposed carbon pollution standards. Commenters stated that a single source category 
63

would also be consistent with the system-based approach EPA has proposed, which has 

important elements that reduce emissions from existing EGUs as a whole rather than solely from 

EGUs utilizing particular fuels or generating technologies. Commenters stated that as a threshold 

matter.

Commenters believed that EPA is therefore free to make reasonable revisions to the source 

category listings, including the consolidation of already-listed source categories, without 

significant new findings. Commenters continued that the proposed consolidation of the source 

categories would be reasonable for at least three reasons. Commenters said, first, steam electric 

generating units and fossil fuel-fired combustion turbines broadly serve the same market 

functions. Commenters stated that not only do units in these source categories all generate 

electricity for wholesale, they also increasingly provide similar types of generating 

service. Commenters noted, in a climate of competitive natural gas prices and relatively high 

coal prices, coal-fired steam electric generating units now commonly provide intermediate or 

even peaking generation service rather than playing their traditional role as baseload 

resources. Commenters stated as coal generation has declined, gas-fired combustion turbines -

especially NGCC facilities - have become intermediate or baseload resources rather than 

providing primarily peaking service. Commenters stated that combining these two source 

categories to reflect their converging market functions, as we recommend, would be consistent 

with the categorization contemplated by Congress when it originally enacted section 111 in 

1970. (417 The legislative history of the 1970 Clean Air Act indicates that Congress expected 

EPA would establish standards within broad functional categories of facilities. One 

representative, for example, stated that EPA "could establish uniform pollution control standards 

for the chemical, oil refining, foundries, food processing, and cement- making industry, and 

other industries. . . . Every plant within the same group could be required to maintain the same 

high standards." 116 Cong. Rec. 19,218 (1970) (statement of Rep. Vanik).)

Commenters stated that it would also be consistent with the history of these particular source 

categories; for example, in 2005, EPA transferred integrated gasification combined cycle (IGCC) 

facilities to the steam electric generating unit source category on the grounds that IGCC facilities 

serve the same function. (418 See 77 Fed. Reg. 22392, 22,411/1 (April 13, 2012).) Commenters

stated it would be consistent with various other instances in which EPA has established broad 

categories encompassing multiple types of sources that serve the same function, even though 

those source categories may encompass facilities using disparate fuels and industrial processes. 

(419 For example, EPA designated a single NSPS for multiple copper smelting production 

methods as early as 1976. See 41 Fed. Reg. 2332-2333 (Jan. 15, 1976). Similarly, EPA's rotary 

lime kiln source category includes units fueled by coal, natural gas, and oil. See 47 Fed. Reg. 

38832, 38843 (Sept. 2, 1982); see also 40 C.F.R. Section 60.340(a), 60.342. And most recently, 

EPA included all Portland cement plants (e.g. "long wet," "long dry," "preheater," and "preheater 

with precalciner") in a single source category. 75 Fed Reg. 54970, 55,010-55,012, 55,015 (Sept. 

9, 2010). This decision was ultimately held by the D.C. Circuit. See Portland Cement 

Association v. EPA, 665 F.3d 177, 190-93 (D.C. Cir. 2011).

Commenters noted, second, the consolidation of these two source categories would be consistent 

with the system-based nature of the BSER that EPA has proposed in these emission guidelines. 

Importantly, commenters stated that the four building blocks in EPA's BSER are intended to 
64

function in concert to reduce emissions from all EGUs across the two source categories. 

Commenters stated that the effects of any individual building block on any one type of EGU, 

however, will depend upon power market dynamics. Commenters noted, for example, building 

blocks 3 and 4 - which involve shifting generation to zero-carbon resources such as renewable 

energy and energy efficiency - displace the need for both generation from fossil fuel-fired 

combustion turbines and steam electric generating units. Commenters stated the extent to which 

these building blocks reduce generation from one or both types of EGUs, however, can vary by 

region of the country and even by season of the year. Commenters noted that establishing a 

single source category for both steam electric generating units and fossil fuel-fired combustion 

turbines would be consistent with the broad nature of the BSER that EPA has proposed, and 

simplify EPA's analysis by ensuring that all emission reductions from that BSER are attributed to 

one source category. Commenters said that a single source category would also be consistent 

with the nature of the power sector. Utilities and independent system operators make dispatch 

decisions for the entire fleet of power plants without regard to whether those power plants are 

fueled by coal, natural gas, nuclear energy, or renewable resources.

Commenters stated that operating the grid in this way allows utilities to dispatch the least 

expensive available generating resources. Commenters noted that states and utilities may choose 

to consider compliance options for EPA's forthcoming 111(d) standards that follow similar 

principles, just as EPA's proposed system-based BSER reflects the capability of the electric 

system to achieve overall reductions in carbon pollution by increasing output from lower and 

zero-emitting resources. Lastly, commenters noted that the adoption of a broad source category 

encompassing all affected EGUs would not preclude EPA from recognizing appropriate 

subcategories where needed to establish performance standards for new sources. (Nor, 

conversely, would the retention of separate source categories preclude the flexible system of 

emission reduction EPA has proposed for the two categories here, where emission reduction 

opportunities are assessed and compliance allowed to be achieved comprehensively across the 

two categories.) Commenters asserted, Section 111(b), of course, gives EPA broad discretion to 

"distinguish among classes, types, and sizes within categories of new sources" by establishing 

subcategories when prescribing standards for new sources. (420 42 USC - 7411(b)(2).)

Commenters supported combining the two existing categories into a single category for purposes 

of carbon emissions from existing affected EGUs and supports EPA's proposal to codify all of 

the proposed requirements for the affected EGUs in a new subpart, 40 CFR part 60 subpart 

UUUU. Commenters stated that combining the two categories would offer additional flexibility 

by facilitating implementation of carbon mitigation measures, such as emission trading among 

sources in both categories.

Commenters noted that EPA has revised, combined, or otherwise redistributed sources 

previously subject to different section 111(b) source categories, and such revision or 

combination of source categories is particularly appropriate where, as here, both source 

categories at issue serve the same basic function: to supply power to the grid from the 

combustion of fossil fuels. Commenters concluded, stating that against this backdrop, 

promulgation of emission guidelines for all existing fossil fuel-fired EGUs under a single 

combined source category is both consistent with EPA's prior practice and permissible under the 

statute.
65

Commenters stated that the separate standards of performance for fossil fuel-fired steam 

generating boilers and fossil fuel-fired combustion turbines made sense for regulation of criteria 

pollutants. Commenters noted, however, in the context of regulation of carbon dioxide this 

separation is a historical artifact with no compelling purpose. Commenters stated that separate 

standards could potentially inhibit flexibility in shifting generation from more carbon-intensive 

steam units to less carbon-intensive NGCC units. Commenters believed EPA's 2014 proposal is 

good policy for both Section 111(b) and Section 111(d), and it would promote flexibility and 

facilitate emissions trading. Commenters concluded, stating that for purposes of CO2 regulation, 

they recommend that fossil fuel-fired steam generating boilers and fossil fuel-fired combustion 

turbines should be combined into a single category.

Commenters supported combining the category of coal-fired steam power plants and gas turbines 

(including combined cycle turbines), 79 Fed. Reg. at 34,892. and believed it is appropriate 

because both coal-fired steam power plants and NGCC power plants serve the same function of 

providing base-load and intermediate load electricity, and a single category is also consistent 

with the system-based approach EPA has proposed, which has important elements that reduce 

emissions from existing EGUs as a whole rather than solely from EGUs utilizing particular fuels 

or generating technologies.

Commenters stated since they are not in favor of carbon averaging, they felt that the two existing 

categories, fossil fuel-fired steam generating boilers and fossil fuel-fired combustion turbines 

should be kept separate since one of the state benefits of combining both categories would be 

facilitating emissions trading among sources. 

Commenters opposed the combining of the two existing categories for the affected EGUs into a 

single category, explaining that the NSPS industrial categories have always been defined by 

engineering design and function, and, therefore, the two respective categories for steam EGUs 

and NGCC units should remain separate for this reason.

Commenters stated that the California utilities support the EPA's proposal to combine the two 

source categories for purposes of regulating CO2 emissions in a new subpart UUUU. 

Commenters noted that as the EPA implies in the Proposed Rule, such an approach may enable 

the development of a more flexible program for existing sources under Section 111(d) by 

facilitating implementation of CO2 mitigation measures, such as shifting generation from higher 

to lower-carbon intensity generation among existing sources (e.g., shifting from boilers to NGCC 

units) or facilitating emissions trading among sources. Commenters added that such flexibility 

should present opportunities for reducing the cost of achieving emission reductions under 111(d) 

and offers, for example, researchers at Resources for the Future who have demonstrated that a 

given GHG abatement objective under 111(d) can be achieved at lower cost by looking across all 

fossil-fuel units for abatement rather than only at coal units. (52 See Burtraw, Dallas and 

Woerman, Matt, Technology Flexibility and Stringency for Greenhouse Gas Regulations. RFF 

Working Paper, July 2013.)

Commenters stated that EPA creates this new source category - the integrated electric grid -

treating the grid as if it is a "single emitting unit" for purposes of the CPP
66

Commenters stated the EPA may regulate "industrial categories" that "cause or contribute 

significantly" to air pollution. 42 U.S.C. section 7411(b). Commenters said the EPA recognizes 

that greenhouse gas emissions contribute to global pollution and that no single source has the 

power to influence, alone, the pollution load that affects humanity. Commenters stated this is 

fundamentally different from any other pollutant regulated under the CAA, which may suggest 

why Congress did not directly tackle GHGs in at least 1990 if not earlier. Commenters said GHG 

is a matter for the State Department, not the EPA.

Commenters stated this fundamental difference leads the EPA to the conclusion - a correct one -

that individual fossil-fired units, those traditionally regulated under Section 111, should not bear 

the burden of fixing a global problem. Commenters said but then the EPA starts to veer from this 

reality. Commenters stated the EPA creates this new source category - the integrated electric grid 

- treating the grid as if it is a "single emitting unit" for purposes of the CPP. Commenters said the 

EPA reasons that, as long as reductions come from the generation or use of electricity, those 

reductions will fundamentally affect the nation's GHG pollution loading.

Commenters stated that earlier this year, they submitted comments regarding EPA's proposed 

new source performance standards for greenhouse gas emissions from the electric power sector 

(Docket Number EPA-HQ-OAR-201 3-0495). Commenters said their comments were attached 

as Appendix C. Commenters argued that EPA should combine coal and gas electric generating 

units (EGUs) into a single source category for purposes of those proposed standards. 

Commenters urged EPA to use its broad legal authority under section 111(b) to revise source 

category definitions and merge all EGUs subject to new and existing-source greenhouse gas 

performance standards into a single source category, and to do so in consistent fashion across the 

two rulemakings. 

2.6 COMMENTS REGARDING SUBCATEGORIZATION

This section addresses comments received on subcategorization.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Subcategory for small public and cooperative utilities.

Response 1: Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to 

subcategorize classes of facilities for purposes of setting emissions standards under section 

111(d) of the Clean Air Act (which does not itself require that the EPA establish facility 

subcategories). Section 60.22(b) (5) provides that EPA will “specify different emission 

guidelines . . . for different sizes, types, and classes of designated facilities when costs of control, 

physical limitations, geographical locations, or similar factors make subcategorization 

appropriate.” There is thus no requirement that the EPA establish additional subcategories under 
67

section 111(d) unless it finds that such subcategories are “appropriate.” In this rule the EPA has 

determined that it is appropriate to specify emission guidelines for two subcategories of existing 

fossil fuel-fired EGUs: fossil fuel-fired electric utility steam generating units, and stationary 

combustion turbines. The EPA is not finalizing any further subcategories because it has 

determined that all affected EGUs can achieve the relevant performance standard set by applying 

the BSER to each of these two subcategories. This approach is also consistent with the EPA’s 

approach in the final rule establishing standards of performance for greenhouse gas emissions 

from new, modified, and reconstructed sources, which defines the same two subcategories. 

Further discussion of the EPA’s approach to subcategorization can be found in the preamble to 

the final rule for existing sources in sections V.A and V.B.

The following are summaries of the specific public comments under this comment:

Commenters stated that based on the challenges faced by AEPCO and similarly-situated small 

public and cooperative non-profit utilities, they requested that EPA consider creating a separate 

category for "small public and cooperative utilities" that provides relief to these small entities, 

ensuring their ability to continue providing basic services, while also providing for reasonable 

reductions in carbon emission rate and mass. Commenters explained that they believe that the 

category should be limited to public or cooperative entities that sell 4 million MWh or less of 

energy, consistent with the FERC definition. 16 USC 824(f). Commenters estimated that there 

are 23 cooperatives and 75 small public utilities that fit into this category based on 2012 data, 

and in order to qualify for relief, the small public or cooperative utility would need to 

demonstrate, applying EPA's building blocks only to its existing system resources, that: 1) One 

or more affected EGUs (a "non-achieving unit") cannot meet the relevant state Interim Goal or 

Final Goal; AND 2) Such non-achieving unit(s) make up 20% or more of the small public or 

cooperative utility's generating capacity; AND , 3) Shutting down the unit in 2020 (or 2030) 

would occur prior to the end of the unit's remaining useful life; AND 4) The cost of building a 

replacement, NSPS-compliant unit together with the cost of paying down debt on the existing 

non-achieving units, would be excessive. Commenters stated that in essence, this test is meant to 

identify only those small public and cooperative utilities that are severely affected by the 

proposed Clean Power Plan both in terms of costs of compliance and loss of generation capacity 

required to serve member load. Commenters requested EPA provide relief to small public and 

cooperative utilities. Commenters requested that "EPA consider creating a separate category for 

small public and cooperative utilities that provides relief to these small entities." Commenters

looked at EPA, EIA and FERC databases and found 98 entities for the small public and 

cooperative utility alternative category which generate about 60,618,920 metric tons. If all of 

these units were in the cooperative utility alternative category and achieved an overall 15 percent

reduction then about 9,092,838 metric tons would be reduced. Commenters stated that compared 

to EPA's calculated 730,000,000 metric ton reduction, at most the leakage would be 1.2 percent

of the total tonnage.

Commenters, operators of small, rural, consumer-owned, public electric cooperative having a 

membership with one-third of all members below the federal poverty line, respectfully requested 

that the final rule include a separate subcategory for small public and cooperative non-profit 

utilities to ensure that these small entities can continue to provide basic services to their 

members. Commenters explained how small, rural, member-owned cooperatives cannot raise 
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capital like traditional investor-owned utilities, and commenters provided analyses indicating the 

costs of compliance would drive up electricity rates by sixty to eighty percent; commenters

asserted that such rate increases are un-sustainable for members of the cooperative. Commenters

provided analyses that indicated the prescribed federal targets for states preclude sufficient 

flexibility in the proposed guidelines to allow any viable compliance options for ongoing 

operation of their only generating station. Commenters stated that the financial hardship imposed 

by the proposed rule will likely force the cooperative to dissolve, leaving all the assets at the 

generating station as stranded assets. Commenters believed that the proposal will potentially 

have a similar effect on other small cooperative power plants, imposing extravagant costs and 

potentially jeopardizing the vital role of cooperatives in delivering power to rural America. 

Commenters described their recommended applicability criteria for a new subcategory for small 

public and cooperative utilities that commenters believed should be included in the final rule:

1. Commenters stated that the EPA should use the same size threshold used by FERC, 4 

million MWh or less in net electric sales; see 16 U.S.C. Section 824(f). 

2. Commenters stated that one or more of the EGUs owned by the cooperative should be 

unable to meet the relevant state goals. 

3. Commenters stated that shutting down the unit in 2020 or 2030 would result in shutting 

the unit down prior to the end of the remaining useful life. 

4. Commenters stated that the cost of building a replacement unit together with paying off 

the debt of stranded assets (non-compliant units) should be excessive. 

Commenters explained that their cooperative operates only one power generation facility, 

Apache Generating Station. Commenters described the construction and installation of the 

individual units at the station, and describes the units that may be "affected EGUs" subject to the 

proposed Section 111(d) requirements. Commenters described their limited financial capabilities 

and that their members are independent entities that make power and energy purchase decisions 

based on the best interest of their members. Commenters described their earnings position and 

internal financing capacity.

Commenters stated that the EPA's regulations governing the promulgation of the Guidelines for 

State Plans clearly give the EPA the authority to promulgate subcategories and the EPA has 

routinely exercised such authority under the general NSPS program. Section 60.22 provides in 

relevant part: "The Administrator will specify different emission guidelines or compliance times 

or both for different sizes, types, and classes of designated facilities when costs of control, 

physical limitations, geographical location, or similar factors make sub-categorization 

appropriate." Commenters cited 40 CFR 60.22(b) (5).

Commenters stated, that in this case, the costs of control and financial limitations of the entities 

involved (small public or cooperative utilities, which are non-profit) provide a strong basis for 

subcategorization and providing both a more relaxed limit (meeting the building blocks on the 

system only, with a target of reaching the State goals or 15 percent overall reduction, whichever 

is less) and a more relaxed time frame (providing a longer period to reach the overall reduction, 

up to but not to exceed the remaining useful life of the affected EGU).
69

Commenters expressed concerns about applying the proposed rule to small municipal power 

plants and requested that the final rule allow states to subcategorize small units, and commenters

requested that the final federal guideline allow states maximum flexibility to address municipal 

power concerns.

Commenters stated that the proposal did not acknowledge the discretion of states to address 

unique circumstances of certain small utilities, and commenters stated that the final rule should 

specifically address the ability of states to develop specific exceptions for dispersed communities 

(such as Native American communities) served by small utilities with limited options for 

providing electricity service to these remote communities. Commenters recommended that the 

final rule should define a "small utility" using the same definition set forth at 16 USC 824(f): a 

rural cooperative that sells less than 4,000,000 megawatt hours of electricity per year.

Commenters supported exemption of small public power cooperatives but stated that if the final 

guideline must apply to small public power cooperatives, the final rule should include a 

subcategory for small public and cooperative utilities defined as those with less than 4 million 

MWh of annual sales. Commenters cited another cooperatives estimate that the cost of 

complying with the proposal would increase electric costs to customers by 40 percent and 

commenters supported an alternative plan based on the proposed subcategory that would reduce 

this increase to under 10 percent, and commenters believed that the proposed subcategory for 

small public and cooperative utilities is consistent with Congress' goals for small entities in the 

Regulatory Flexibility Act. Commenters stated EPA's legal analysis of the proposed Clean Power 

Plan rule suggests that States implementing this rule may have the authority to subcategorize 

sources to take into account costs, impacts and other factors. Commenters stated MMEA 

emphasizes that small public power systems and units, particularly systems with only one unit or 

a few units, are in a class of their own when it comes to challenges under this proposed 

rule. Commenters added EPA should thus make explicit and clear in its final rule that States 

should take this into account, and that States have authority to exclude small public power from 

the rules, allocate hardship credits to these units in the form of less stringent or more flexible 

standards, or otherwise provide flexibility and support to these units.

Comment 2: Subcategory for unit’s combusting lignite coal.

Response 2: Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to 

subcategorize classes of facilities for purposes of setting emissions standards under section 

111(d) of the Clean Air Act (which does not itself require that the EPA establish facility 

subcategories). Section 60.22(b) (5) provides that EPA will “specify different emission 

guidelines . . . for different sizes, types, and classes of designated facilities when costs of control, 

physical limitations, geographical locations, or similar factors make subcategorization 

appropriate.” There is thus no requirement that the EPA establish additional subcategories under 

section 111(d) unless it finds that such subcategories are “appropriate.” In this rule the EPA has 

determined that it is appropriate to specify emission guidelines for two subcategories of existing 

fossil fuel-fired EGUs: fossil fuel-fired electric utility steam generating units, and stationary 

combustion turbines. The EPA is not finalizing any further subcategories because it has 
70

determined that all affected EGUs can achieve the relevant performance standard set by applying 

the BSER to each of these two subcategories. This approach is also consistent with the EPA’s 

approach in the final rule establishing standards of performance for greenhouse gas emissions 

from new, modified, and reconstructed sources, which defines the same two subcategories. 

Further discussion of the EPA’s approach to subcategorization can be found in the preamble to 

the final rule for existing sources in sections V.A and V.B.

The following are summaries of the specific public comments under this comment:

Commenters stated that sub-categorization is necessary and appropriate for lignite-mine-mouth 

EGUs and other subcategories because sub-categorization allows the Agency to address key 

characteristics of the various types EGUs. Commenters stated that the final rule should include a 

subcategory that reflects the unique physical, geographic, and financially related characteristics 

of lignite mines and mine mouth power plants because lignite has unique physical characteristics 

including a higher moisture content that makes it un-economical to transport over long distances. 

Commenters stated that lignite-fired EGUs are always constructed at or near a lignite mine. 

Commenters stated that establishing a subcategory for lignite units under the section 111(d) rule 

would be consistent with Agency determinations under the MATS rule. Commenters believed

that any closure of a lignite-fired EGU (to comply with a 111(d) state plan) may result in the 

permanent shutdown of the associated lignite mine, and commenters believed this result is 

inconsistent with the longstanding U.S. energy policy that has encouraged utilization of domestic 

lignite resources. Commenters stated that the shutdown of a lignite energy complex (i.e., a lignite 

mine and lignite-fired EGU) compounds the effects of the closure and causes a 

disproportionately greater impact on the regulated entity, the mining company and the local 

communities because of large losses of capital as stranded assets and foreclosed investments and 

the loss of technological advancements in clean coal technology at lignite-fired EGUs supported 

by federal tax credits. Commenters also stated that closure of these facilities yields higher job 

loss totals; higher consumer energy bills due to accelerated cost recovery in regulated markets; 

and crippling local economic impacts.

Commenters stated that sub-categorization of lignite-mine-mouth EGUs is also warranted 

because EGUs that use lignite routinely enter into long-term fuel supply contracts to gain 

protection against fuel price volatility. Commenters stated that mine-mouth plants throughout the 

country are parties to long-term supply contracts whose maximum expiration dates range from 

2016 to 2057 with a typical contract term ranging from 20-40 years. Commenters stated that 

these contracts were arranged prior to the date of proposal and are unique to lignite mines and 

mine-mouth plants, and commenters stated that sub-categorization is warranted because the 

parties to these contracts have made significant investments of financial and human capital.

Commenters stated that the final rule should include a separate subcategory for lignite-fired 

power plants that contemplates the unique characteristics of lignite-fired EGUs and that reflects 

technological and operational differences when compared to traditional coal-fired EGUs. 

Commenters stated that a lignite subcategory should include more relaxed emissions limits 

because the physical and chemical characteristics of lignite yield a lower heating-value than 

other types of coal, resulting in the need to combust additional fuel per megawatt hour of 

electrical output. Commenters also stated that the physical and chemical composition of lignite 

also requires larger, more energy intensive, control technologies (compared to other coal-fired 
71

units) with higher auxiliary loads and lower net electrical output per million Btu of heat 

input. Commenters also stated that the final guidelines should include a separate subcategory for 

lignite-fired EGUs because these units provide electricity to regions of the country that are not 

served by natural gas pipelines or alternative coal supplies. Commenters did not believe that the 

proposal properly considered the large regions of the United States that are dependent on lignitefired generation. Commenters stated that without a subcategory for lignite-fired EGUs, operators 

of existing lignite-fired power plants may be required to shut down, forfeiting use of extremely 

valuable and affordable generating units, and such shutdowns would also require those units to 

forfeit access to domestic, plentiful, and affordable lignite. Commenters believed the proposed 

rule will terminate the ability of co-located mine-mouth plants to conduct modifications or 

reconstruction, as well as the ability to recover potentially sizable investments in their mines 

because of the limitations placed on an operator's ability to maintain, expand, or add capacity to 

use these local, domestic, and sizeable fuel supplies.

Comment 3: Subcategory for low-emitting units.

Response 3: Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to 

subcategorize classes of facilities for purposes of setting emissions standards under section 

111(d) of the Clean Air Act (which does not itself require that the EPA establish facility 

subcategories). Section 60.22(b) (5) provides that EPA will “specify different emission 

guidelines . . . for different sizes, types, and classes of designated facilities when costs of control, 

physical limitations, geographical locations, or similar factors make subcategorization 

appropriate.” There is thus no requirement that the EPA establish additional subcategories under 

section 111(d) unless it finds that such subcategories are “appropriate.” In this rule the EPA has 

determined that it is appropriate to specify emission guidelines for two subcategories of existing 

fossil fuel-fired EGUs: fossil fuel-fired electric utility steam generating units, and stationary 

combustion turbines. The EPA is not finalizing any further subcategories because it has 

determined that all affected EGUs can achieve the relevant performance standard set by applying 

the BSER to each of these two subcategories. This approach is also consistent with the EPA’s 

approach in the final rule establishing standards of performance for greenhouse gas emissions 

from new, modified, and reconstructed sources, which defines the same two subcategories. 

Further discussion of the EPA’s approach to subcategorization can be found in the preamble to 

the final rule for existing sources in sections V.A and V.B.

The following are summaries of the specific public comments under this comment:

Commenters stated that the final guideline should include a low-emitting-state subcategory with 

streamlined compliance requirements for states (like Idaho) that achieve low carbon intensities. 

Commenters believed the most straightforward way to recognize the success of states with low 

carbon emissions is to establish a minimum emissions performance goal (i.e., "minimum federal 

requirements") below which no additional reductions would be required. Commenters believed

the legal mechanism for establishing a minimum goal is sub-categorization which the Agency 

has historically used to address the wide variety of sources regulated under 111(d) and 

commenters noted that the 111(d) regulations were specifically amended to "make clear that the 
72

Administrator will specify different emission guidelines for different sizes, types, and classes of 

[existing sources] when costs of control, physical limitations, geographical location, and similar 

factors make sub-categorization appropriate." 40 Fed. Reg. 53340, 53341 (Nov. 17, 1975). 

Commenters believed that since EPA has created subcategories on a state-wide basis, then the 

final rule should create an additional subcategory that would include any states with certain instate generating characteristics (e.g., low existing emissions, no coal generation, 111(b) 

compliant gas generation, significant existing renewable generation) that provide assurance that 

carbon emissions will remain low. After establishing the low-emitting-state subcategory, 

commenters believed the final rule should then determine a separate BSER and establish an 

emission guideline with a specific emission threshold that could not be exceeded, rather than an 

emissions goal based upon application of the four building blocks; states within this low emitter 

subcategory would not be required to comply with the full state performance plan requirements 

contemplated in the proposed rule, but instead would need to submit only a streamlined state 

plan that provided for continued compliance with the threshold emissions rate. Commenters

believed that this approach is consistent with the overall purposes of the proposed rule and 

allows a more equitable and cost-effective result for states like Idaho with no in-state coal 

generation and a demonstrated record of low carbon output because it avoids the economic 

inefficiencies associated with seeking to achieve marginal CO2 reductions from states with little 

or no fossil generation. Commenters proposed that the final guideline establish a low-emittingstate subcategory that would include states that have no coal generation and attain emission rates 

below 550 lbs of CO2/MWh before or during the compliance period. Commenters stated that 

based on 2012 emissions data, only Idaho is below this threshold but that other states would be 

expected to achieve this threshold later in the compliance period and could modify state planning 

requirements when the goal was achieved, providing incentive to accelerate emissions 

reductions.

Comment 4: Subcategory for supercritical pulverized coal (SCPC) units.

Response 4: Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to 

subcategorize classes of facilities for purposes of setting emissions standards under section 

111(d) of the Clean Air Act (which does not itself require that the EPA establish facility 

subcategories). Section 60.22(b) (5) provides that EPA will “specify different emission 

guidelines . . . for different sizes, types, and classes of designated facilities when costs of control, 

physical limitations, geographical locations, or similar factors make subcategorization 

appropriate.” There is thus no requirement that the EPA establish additional subcategories under 

section 111(d) unless it finds that such subcategories are “appropriate.” In this rule the EPA has 

determined that it is appropriate to specify emission guidelines for two subcategories of existing 

fossil fuel-fired EGUs: fossil fuel-fired electric utility steam generating units, and stationary 

combustion turbines. The EPA is not finalizing any further subcategories because it has 

determined that all affected EGUs can achieve the relevant performance standard set by applying 

the BSER to each of these two subcategories. This approach is also consistent with the EPA’s 

approach in the final rule establishing standards of performance for greenhouse gas emissions 

from new, modified, and reconstructed sources, which defines the same two subcategories. 
73

Further discussion of the EPA’s approach to subcategorization can be found in the preamble to 

the final rule for existing sources in sections V.A and V.B.

The following are summaries of the specific public comments under this comment:

Commenters suggested newer, highly efficient supercritical pulverized coal (SCPC) units should 

be exempt from the section 111(d) rule or included in a separate subcategory that recognizes the 

newer SCPC technology as BSER for that subcategory because commenters believed it is 

unreasonable to make these highly efficient units subject to a standard that could require further 

capital investments for marginal efficiency improvements.

Commenters, the operator of a highly efficient supercritical coal-fired boiler, expressed concerns 

that the section 111(d) rule could be used by state regulators to force his plant to incur expensive 

modifications to make his plant even more efficient than it already is. Commenters did not think 

this is appropriate because his plant is already one of the most efficient plants in the country. 

Commenters noted that the proposed rule did not exempt highly efficient EGUs, and commenters

suggested that the EPA evaluate the need for developing a standard of performance that would 

limit the possibility that additional reductions could be required at highly efficient units. 

Commenters acknowledged that that EPA may view individual unit treatment as a state 

responsibility, but commenters believed there are many highly efficient units across the U.S. and 

that a consistent federal guideline is necessary to ensure that interstate power markets are not 

unfairly tilted by inconsistent treatment of highly efficient units in state plans.

Comment 5: EPA should revise its proposal to conform to previous rules, all of which support 

subcategorized, nationally applicable unit-by-unit standards based on fuel and technology.

Response 5: Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to 

subcategorize classes of facilities for purposes of setting emissions standards under section 

111(d) of the Clean Air Act (which does not itself require that the EPA establish facility 

subcategories). Section 60.22(b) (5) provides that EPA will “specify different emission 

guidelines . . . for different sizes, types, and classes of designated facilities when costs of control, 

physical limitations, geographical locations, or similar factors make subcategorization 

appropriate.” There is thus no requirement that the EPA establish additional subcategories under 

section 111(d) unless it finds that such subcategories are “appropriate.” In this rule the EPA has 

determined that it is appropriate to specify emission guidelines for two subcategories of existing 

fossil fuel-fired EGUs: fossil fuel-fired electric utility steam generating units, and stationary 

combustion turbines. The EPA is not finalizing any further subcategories because it has 

determined that all affected EGUs can achieve the relevant performance standard set by applying 

the BSER to each of these two subcategories. This approach is also consistent with the EPA’s 

approach in the final rule establishing standards of performance for greenhouse gas emissions 

from new, modified, and reconstructed sources, which defines the same two subcategories. 

Further discussion of the EPA’s approach to subcategorization can be found in the preamble to 

the final rule for existing sources in sections V.A and V.B.
74

The following are summaries of the specific public comments under this comment:

Commenters stated the EPA's previous rules under section 111-including those issued under 

section 111(d)- support the establishment of separate nationally applicable emission standards 

for EGUs based on technology, fuel type, and other relevant characteristics. Commenters said for 

example, in previous guidelines issued under section 111(d), the EPA has subcategorized among 

existing municipal solid waste combustors based on unit size and on the facility's aggregate 

combustion capability. Commenters stated the EPA has also established separate section 111 (d) 

guidelines based on the type of input that the stationary source is designed to combust. 

Commenters said thus, the EPA's previous section 111(d) rules provide ample support for the 

proposition that the EPA must consider subcategorizing based on unit size, configuration, and 

fuel input. Commenters stated the EPA's section 111(b) performance standards for EGUs 

including those proposed by the EPA in tandem with this Proposed Rule- also uniformly support 

the need to subcategorize among existing sources based on fuel source, configuration, and 

perhaps other factors. Commenters stated for example, requirements under NSPS categories Da 

(fossil-fueled boilers) and KKKK (fossil-fueled combustion turbines) have historically been 

separate, even for pollutants which both categories produce. Commenters stated likewise, the 

EPA's current CO2 NSPS proposals for both new and modified sources differentiate among 

EGUs based on fuel source and heat rate.

Comment 6: The focus of section 111 on individual sources requires a highly subcategorized 

emission guidelines within a broad source category like existing fossil fuel-fired EGUs.

Response 6: Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to 

subcategorize classes of facilities for purposes of setting emissions standards under section 

111(d) of the Clean Air Act (which does not itself require that the EPA establish facility 

subcategories). Section 60.22(b) (5) provides that EPA will “specify different emission 

guidelines . . . for different sizes, types, and classes of designated facilities when costs of control, 

physical limitations, geographical locations, or similar factors make subcategorization 

appropriate.” There is thus no requirement that the EPA establish additional subcategories under 

section 111(d) unless it finds that such subcategories are “appropriate.” In this rule the EPA has 

determined that it is appropriate to specify emission guidelines for two subcategories of existing 

fossil fuel-fired EGUs: fossil fuel-fired electric utility steam generating units, and stationary 

combustion turbines. The EPA is not finalizing any further subcategories because it has 

determined that all affected EGUs can achieve the relevant performance standard set by applying 

the BSER to each of these two subcategories. This approach is also consistent with the EPA’s 

approach in the final rule establishing standards of performance for greenhouse gas emissions 

from new, modified, and reconstructed sources, which defines the same two subcategories. 

Further discussion of the EPA’s approach to subcategorization can be found in the preamble to 

the final rule for existing sources in sections V.A and V.B.

The following are summaries of the specific public comments under this comment:
75

Commenters stated that 40 CFR Part 60 Subpart B and the history of section 111 standards 

confirms a focus on individual sources, and commenters cited regulatory text from 40 CFR 

60.22(b)(5) as requiring 111(d) proceedings to reflect highly subcategorized emission guidelines 

within a broad source category like existing fossil fuel-fired EGUs.

Comment 7: Subcategorization by coal type.

Response 7: This comment is generally consistent with the EPA’s approach for building block 1, 

but for the reasons discussed in the preamble, the additional reductions from building blocks 2 

and 3 are available and important to obtain. We address our authority to subcategorize in the 

preamble.

The following are summaries of the specific public comments under this comment:

Commenters argued that EPA is expressly authorized to subcategorize among units by its own 

regulations. See 40 C.F.R. section 60.22(b) (5). Commenters said an analysis of the CO2

emissions characteristics of coal units by coal type could identify groups of "top-performing" 

units with low emission rates, reflecting specific design, operating, and other engineering aspects 

of the units. Commenters noted that a statistical analysis could determine the average emission 

rate of a subset of top-performing units, such as the top 75th or 90th percentile. Commenters said 

measurement, which would represent an emission standard under Section 111(d) that reflects the 

"best system of emission reduction," could be applied to all units burning similar coal types (e.g., 

bituminous/sub-bituminous and lignite) to determine an emission limit applicable to all units in a 

particular subcategory, with "outside-the-fence" compliance flexibility at states' discretion. 

Commenters stated that this standard in turn could be converted by states to a CO2 tonnage 

reduction goal that could be met using a combination of inside-the-fence or outside-the-fence 

measures.

Comment 8: Subcategorization by age of facility.

Response 8: The EPA disagrees with the comment that the final rule should include a 

subcategory based on the age of the facilities it seeks to regulate. Further discussion of the EPA’s 

approach to subcategorization can be found in the preamble to the final rule for existing sources 

in sections V.A and V.B.

The following are summaries of the specific public comments under this comment:

Commenters stated that the final rule should include a subcategory based on the age of the 

facilities it seeks to regulate because the Act requires consideration of the remaining useful life 

in setting section 111(d) standards, and the commenters believed that the age of an EGU 

determines a number of factors that EPA considers when determining whether sub-categorization

is appropriate. The commenters stated that sub-categorization could be used to encourage the 

operation of newer, more efficient EGUs, and the commenters believed it is reasonable for the 
76

final rule to include a subcategory of EGUs constructed after 1978 (i.e., facilities constructed 

after the Power Plant and Industrial Fuel Use Act took effect) because such subcategorization 

would largely eliminate the threat of facilities being forced to shut down prior to the end of their 

remaining useful lives.

2.7 OTHER

This section addresses comments received on other topics relevant to this chapter. 

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Support for exclusion of Integrated Gasification Combined Cycle units from 

implementing building block 1 requirements.

Response 1: The EPA thanks the commenters.

The following are summaries of the specific public comments under this comment:

Commenters supported the proposal to exclude Integrated Gasification Combined Cycle units 

from implementing building block 1 requirements for the reasons cited in the preamble to the 

proposed rule and the technical support documents.

Comment 2: Inclusion of unit’s combusting coal refuse fuel.

Response 2: This final rule does not include an exemption for coal refuse-fired units. See 

section III.E of the final rule preamble of the NSPS for discussion of the use of coal refuse as 

fuel.

The following are summaries of the specific public comments under this comment:

Commenters urged the EPA to provide an exemption for coal refuse-fired units because, 

commenters asserted, EGUs that burn over 75 percent coal refuse on an annual basis have no net 

GHG emissions in the long term since unused coal refuse piles are constantly burning due to 

their size and exposure to atmospheric oxygen. Commenters stated that there are multiple 

environmental benefits gained from remediating coal refuse piles and that exemption of EGUs 

firing coal refuse is consistent with Building Block 3. Commenters, residents that have

personally witnessed the benefits of remediating numerous legacy, abandoned waste-coal sites 

around their states’ coal fields, stated that EGUs that use waste-coal should be exempted from 

the federal guidelines because use of waste coal to generate and sale electricity has provided the 

funds necessary for the State of Pennsylvania to recover from their "number one environmental 

catastrophe."
77

Commenters stated that the final rule should include a subcategory for EGUs that burn coal 

refuse in circulating fluidized bed (CFB) boilers because this unique technology was developed 

to accommodate use of fuels with widely disparate and variable characteristics and because 

reclamation of abandoned coal-refuse piles (that otherwise auto-ignite and release GHGs with no 

beneficial heat recovery) has unique nonair quality health and environmental benefits that must 

be considered by the EPA and states under section 111(a)(1). Commenters stated that these 

EGUs must be located close to legacy coal-waste piles because it is not cost-effective to ship the 

coal-refuse which has a high weight percentage of inert material and a corresponding low energy 

density. Commenters stated that CAA section 111(d) authorized the EPA to promulgate federal 

guidelines for SIP-like plans that establish state standards of performance for existing sources 

that meet the same applicability criteria (other than the date of construction or modification) 

established for new sources under section 111(b). Commenters stated that section 111(d) requires 

the EPA to permit each state to apply a standard of performance on a case-by-case basis to any 

particular existing source that considers, among other factors, remaining useful life. 

Commenters quoted the CAA section 111(a)(1) definition of "standard of performance," and 

commenters concluded that the sum of the statutory requirements under paragraphs 111(d) and 

111(a)(1) requires federal and state authorities to consider, among other factors, (1) the degree of 

emission reductions achievable at individual existing sources; (2) the cost of achieving 

reductions; (3) nonair quality health and environmental impacts; (4) energy requirements; and (5) 

the remaining useful life of the existing sources to which a standard would apply. Based on these 

statutory requirements under section 111(d) and 111(a)(1), commenters believed that the EPA 

should establish a subcategory for coal refuse-fired power plants under both the new and existing 

source rules. For existing coal refuse-fired power plants, commenters believed that the plants 

should not be included in the BSER calculations or the state goals due to the variability of coal 

refuse quality and the lack of a coal refuse market (unlike commercially sold coal) and because 

coal refuse-fired plants should be treated as carbon neutral. Commenters recommended that the 

final rule require existing coal refuse-fired plants to meet work practice standards that require 

routine boiler tune-ups to maintain efficiency in accordance with good engineering practices. 

Commenters stated that any standard issued under section 111(d) that would inhibit coal refusefired power plants from reclaiming abandoned mine sites would not be the best system available 

based on paragraph 111(a)(1) criteria for nonair quality impacts. Commenters also cited the 

factors listed under 40 CFR 60.22(b)(5) as supporting a set of different emissions guidelines for 

coal refuse CFB units, and commenters cited the definition of "emission limitation" in CAA 

section 302(k) to support a work practice standard for coal refuse CFB units.

Commenters stated that the final rule should include a work practices standard for coal refuse 

CFB units that may include the following elements: 

1. Inspect the burner and combustion controls.

2. Inspect the combustion process.

3. Observe damper operations as related to primary air, secondary air and cyclone 

performance.

4. Evaluate windbox pressures, bed pressures, and furnace differential pressure and air 

proportions. 
78

5. Make adjustments and perform repairs to dampers, actuators, controls and sensors where 

needed.

6. Inspect the system controlling the air-to-fuel ratio to ensure optimization of regulated 

emissions and energy efficiency.

7. Maintain pre /post documentation.

8. Periodic inspection of the balance of plant (e.g., the steam and condenser systems and 

turbines) to identify potential leaks or other conditions warranting maintenance, repairs or 

replacement. 

9. Sources would prepare and submit to EPA or state permitting authorities annual reports 

as to implementation of the work practice and related corrective measures.

Commenters stated that from a CO2 emissions perspective, coal-refuse fired units should be 

considered carbon neutral for the following reasons:

• Coal refuse-fired units are limited to using coal refuse within a 100 mile radius of the 

plant.

• The coal refuse piles that provide the fuel for the plants have auto-ignited and burned in 

the past; some are burning now, and if not used for fuel will burn (uncontrolled and 

unutilized) in the future.

• Reclamation and re-vegetation of these sites allows the sites to become carbon sinks.

• Pennsylvania's Alternative Energy Program recognizes coal-refuse as a 

renewable/alternative energy beneficial to the Commonwealth. 

Commenters stated that EPA should ensure that the rule includes protections to ensure that states 

like Pennsylvania cannot exempt dirty energy sources under the plan's framework because these 

exemptions would severely undermine the purpose of the EPA plan. Commenters stated that PA 

Department of Protection is considering exempting coal waste plants from the program, even 

though they emit large amounts of carbon pollution.

Commenters stated that PA describes coal waste as carbon neutral which is not true.

Commenters explained that coal waste burning is a significant source of carbon in PA, and at its 

most efficient, coal waste emits as much CO2 as a conventional coal power plant, and many 

plants are not operating at maximum efficiency. Commenters noted that Pennsylvania's white 

paper (describing how they propose to meet CO2 limits) also describes coal waste as essentially 

carbon neutral, which not correct. Commenters said that of the 18 coal waste burners in the 

country, 14 are in Pennsylvania, and this is a source of carbon significant in Pennsylvania that 

the EPA must consider in developing its 111(d) criteria. Commenters closed, stating that at its 

most efficiency, coal waste emits as much carbon dioxide as a conventional coal power plant and 

many plants are not operating at a top efficiency.
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Comment 3: Retired EGUs, Comment for Supplemental Proposal - Tribal and Territories

Response 3: Affected EGUs in areas of Indian country have to meet the emission performance 

rates or the goal for the specific area of Indian country. They are not treated differently from 

affected EGUs in states. We are not setting goals for any of the territories (or Alaska or Hawaii), 

so affected EGUs in the territories do not have to meet any requirements.

The following are summaries of the specific public comments under this comment:

Commenters supported all the building blocks proposed by the EPA and expansion of those 

building blocks to include retirements, natural gas co-firing and retrofit CCS opportunities plus 

reduced utilization of certain designated facilities. Commenters believed that use of these 

expanded building blocks should be used to calculate target rates for all jurisdictions. 

Commenters believed that carbon capture and sequestration retrofit and new build opportunities 

are available in Indian country and should be included in building block 1. Commenters believed

that the baseline from which reductions are measured should be reduced to reflect any EGU that 

is retired prior to the date of submission of a territorial or Indian country plan. Commenters

believed that the federal guideline should only allow states to include EGU retirements that occur 

after the date of submission of their BSER determinations (i.e., the date of submission of their 

paragraph 111(d) state plans) because such a guideline will encourage territories and tribes to 

submit their CPP compliance plans as early as is practicable. Commenters believed that 

designated facilities that are no longer operating must either permanently retire, and relinquish 

their air permits or they must be included in the jurisdiction's section 111(d) plan, and 

commenters discussed why they think the approach that EPA is taking with idled units on the 

U.S. Virgin Islands (that may still hold valid Title V air permits) is the wrong approach.

Comment 4: Inclusion of Federal and state-owned units.

Response 4: The final rule does not provide an exemption from applicability based on 

ownership. Federal units are not exempt from the requirements of the rule.

The following are summaries of the specific public comments under this comment:

Commenters urged that the proposed standard be amended to include in its scope the regulation 

of existing government-owned or operated power plants like the Capitol Power Plant. 

Commenters stated that facility still occasionally burns coal. Commenters said please do not 

exempt Federal or any unused District of Columbia based facilities from this standard. 

Commenters stated the Capitol should be required to comply with EPA regulations.

Comment 5: Use of appropriate atmospheric lifetime for methane GWP.

Response 5: A response is not required here as this comment is outside the scope of the 

rulemaking. 
80

The following are summaries of the specific public comments under this comment:

Commenters cited a recent analysis (by the IPCC in its Fifth Assessment Report) that methane is 

34 times more potent - pound for pound - than carbon dioxide as a greenhouse gas over one 

hundred years and 86 times more potent over twenty years - the most critical timeframe for 

taking action to avoid climate catastrophe. Commenters stated that climate scientists agree that 

rising levels of greenhouse gas in the atmosphere are causing the Earth to rapidly approach 

critical tipping points, beyond which major changes are likely irreversible due to environmental 

feedbacks, such as the melting of sea ice or thawing of permafrost, which further accelerate 

climate change, and commenters believed this makes the powerful global warming potential 

(GWP) of methane over the next two decades extremely damaging. Commenters disagreed with 

the analyses that supported the proposal because commenters believed the proposal's analyses 

discounted these effects by using an outdated GWP calculation for methane, and by focusing its 

analysis on the less-important hundred year timeframe.

Commenters also stated the proposal ignored the greater impact of methane (compared to CO2) 

on a 10 year timeframe, and commenters stated that use of a 100 year GWP factor was 

inappropriate and that a 10 year GWP factor of 125 should be used.

Comment 6: Final rule should address emissions of methane.

Response 6: See section III.G of the final rule preamble of the NSPS for the EPA’s response to 

this comment.

The following are summaries of the specific public comments under this comment:

Several commenters noted that the rule should include limits for emissions of methane.

Commenters stated that methane, a greenhouse gas 86 times more potent than CO2 in the first 20 

years after it is released into the atmosphere, could undo the benefits of the coal-to-gas switch if 

it is not captured and controlled, and the tools currently exist to do this in a cost-effective 

manner.

Commenters hoped that eventually the EPA will address methane emissions. Commenters stated

additional EPA regulations are needed for the potent greenhouse gas, methane. Commenters

urged the EPA to finalize the proposed limit on carbon emissions as soon as possible, and then 

move on to additional protections needed to curb methane and other greenhouse gas emissions.

Commenters stated that while they recognized that the proposal is designed to address carbon 

emissions within the power sector, they strongly urged the EPA to immediately draft rules that 

address methane. Commenters stated it is an extremely dangerous and potent greenhouse gas that

really needs a comprehensive plan if to avert catastrophic climate change.

Commenters urged folks on the issue of methane. Commenters said methane is such a more 

potent greenhouse gas than carbon, that limits on methane are needed, or some plan to reduce

methane is needed, because that is also fast tracking us on the path towards climate destruction.
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Commenters believed that additional regulations are necessary to complement use of building 

block 2; these commenters believed that the EPA must develop regulations to reduce fugitive 

emissions of methane from coal, oil, and natural gas production, transmission, and distribution 

systems. Commenters believed that building block 2 will accelerate development of natural gas 

resources in the U.S. with potentially significant increases in GHG emissions as methane. 

Commenters stated that natural gas developed from fractured rock is four to five times cheaper 

than most fuels and that producers have ample profit margins to cover the cost of adverse 

environmental impacts and mitigation of fugitives. Commenters also cited studies indicating the 

high fugitive emission rates associated with fractured rock natural gas practices makes use of 

natural gas equivalent or worse than coal on a global warming potential basis. 

Commenters stated that while they understand that focusing on carbon emissions from power 

plants is the Presidential mandate, focusing on carbon emissions to the exclusion of methane 

emissions is problematic. Commenters stated methane is also a potent greenhouse gas and it 

contributes to climate change. Commenters stated that focusing on carbon alone is like checking 

your car's gas tank and ignoring the oil level when the check engine light is on. Commenters

stated clean power must focus on both methane and carbon emissions. Commenters stated to the 

extent power plants use natural gas, and currently about 30 percent of our power plants already 

do, it is imperative that the EPA promulgate and enforce regulations to ensure that the best 

available control technologies are used to detect, prevent, and control methane leakage from 

power plants and related infrastructure.

Commenters believed there need to be EPA rules to address the incredibly potent greenhouse gas 

of methane. Commenters indicated that in Pittsburgh, they have an aging infrastructure that leaks 

methane, and for every ton of CO2 the EPA rules prevent, and the equivalent amount of methane 

is 80 times more destructive in our atmosphere. Commenters stated rules on other greenhouse 

gases are a necessary next step.

Commenters were concerned that a project that their company completed after 2012 to capture 

and use vented methane from a coal mine will count as a carbon increase under the proposed 

rule.

Commenters stated that the EPA cannot change a market based generating system by passing a 

rule because that would bust the basic principle of the market in Texas and that market forces 

may determine that the cheaper sources of electricity cannot displace gas or coal.

Comment 7: Final rule should address methane emissions from oil and gas production.

Response 7: See section III.G of the final rule preamble of the NSPS for the EPA’s response to 

this comment. See section V.D of the final rule preamble of the CPP for the EPA’s response to 

this comment.

The following are summaries of the specific public comments under this comment:
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Numerous commenters indicated that the final rule should address methane emissions from oil 

and gas production.

Commenters opposed the proposal because of building block 2 and the heavy reliance on 

expanding the use of natural gas for electricity generation. These commenters believed that 

increasing the demand for natural gas will increase natural gas venting and fugitive emissions of 

methane from natural gas production, transmission, and distribution. These commenters believed

that the agency must simultaneously promulgate GHG standards for reducing natural gas venting 

and fugitive emissions from natural gas systems. Commenters stated that the proposal to 

designate natural gas and nuclear power as BSER is not based on a documented, internally 

consistent, or fair analysis because the proposal relies heavily on natural gas for carbon emission 

reductions. Commenters stated that the proposal was based only on industry data for venting and 

fugitive methane emissions, and the proposal ignores peer reviewed literature that indicates 

much higher methane emissions from venting and fugitive sources.

Commenters opposed finalizing the proposed rule before the EPA also promulgates a standard 

for natural gas venting and fugitives because if the proposed rule was finalized large-scale 

investments in new gas-fired power plants would soon follow. Commenters were concerned that 

further study by the EPA on fugitive emissions from fracking may indicate emissions are much 

higher than the estimates used for the proposal, and commenters were concerned that curtailing 

fugitive emissions from fracking may be an intractable problem. Given these concerns, 

commenters stated that the Agency will not be in a position to reverse course and require the 

newly constructed gas plants to retire. For these reasons, commenters believed that fugitive 

emissions associated with shale gas must be addressed in the proposed rule.

Commenters, regional networks of grassroots community organizations, stated that the proposed 

rule encourages fuel-shifting from coal to natural gas without considering the significant 

environmental, public health, economic, and societal harms related to the extraction of natural 

gas. Commenters stated that gas development today, which often involves the dangerous process 

of horizontal high-volume hydraulic fracturing ("fracking"), is largely unregulated and enjoys 

broad exemptions from landmark environmental laws, including the Clean Air Act, the Safe 

Drinking Water Act, and laws regulating hazardous wastes. Commenters stated that the proposed 

federal guidelines under CAA section 111(d) go to great lengths to describe the benefits of 

reducing coal consumption, but the proposed guidelines fail to evaluate the negative 

consequences of increased natural gas production and related infrastructure, including air and 

water contamination, unsafe waste disposal, earthquakes, ecological impacts, and damage to 

roads, property, and communities caused by the boom-bust cycle inherent to extractive industry. 

Commenters also submitted a recently assembled compendium of fully-cited reports, studies, and 

articles compiled by Concerned Health Professionals of New York, which describe the many 

risks and harms of fracking, including its impact on climate change. 

Commenters believed that the proposed rule's endorsement of natural gas as a strategy for 

combating climate change is fundamentally flawed and not supported by science. Commenters

disagreed with the proposal's characterization of natural gas as "clean" because commenters

believed that the best science shows that systemic venting and leakage of methane that occurs 

during extraction, processing, and transport, along with carbon dioxide released during its 

combustion, substantially or completely offsets the benefits that natural gas-fired generation has 
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over coal-fired generation with respect to climate change. Commenters recommended that the 

entire supply chain for gas development should be considered as a single process in analyses 

published to support the final federal guidelines for state plans.

Commenters stated that the environmental concerns regarding the use of fracked natural gas are 

numerous and deserve the agency's attention in conjunction with adoption of these 

guidelines. Commenters stated that if the goal is to reduce greenhouse gas emissions, then the 

expected increase in emissions of methane associated with production, transmission, and burning 

of fracked gas must be fully accounted for, and if the goal is to achieve a healthier environment, 

then the increase in air and water pollution associated with the production, transmission, and 

burning of fracked gas must be accounted for and remedied. Commenters provided a link to a 

compendium of the scientific, medical, and media findings that demonstrate the risk and harms 

of fracking.

Commenters stated that it is crucial that methane pollution from natural gas production and 

transport be accounted for and reduced as part of an overall strategy to reduce carbon emissions 

and combat climate change, and President Obama has committed to taking action on methane as 

part of his Climate Action Plan. Commenters stated that it is vital that EPA, along with its sister 

agency the Department of Interior's Bureau of Land Management, move forward with strong 

rulemaking to limit methane pollution from new and existing sources of natural gas and oil 

production on both public and private lands; otherwise, emissions reductions from use of natural 

gas at power plants may not be realized.

Commenters stated the proposed rule for existing power plants is only a first step in fulfilling our 

obligation to protect the health of our residents while meeting the challenge of climate 

change. Commenters urged the EPA to continue to take action in regulation of methane 

emissions as prescribed in the Climate Action Plan from March 2014 Strategy to Reduce 

Methane Emissions. Commenters stated that according to the IPCC, methane as a greenhouse 

gas is more than 80 times potent as carbon dioxide over a 20-year period. Commenters stated 

that wellheads, pipes, valves, pressures, and even abandoned wells are releasing increasing 

volumes of methane into our atmosphere. Commenters stated that about 30 percent of all 

methane emissions are derived from natural gas and petroleum systems. Commenters stated that

best practices and appropriate regulation must be enacted and enforced to reduce this greenhouse 

gas. Commenters stated the EPA must assume responsibility for setting the standards to 

minimize the risk.

Commenters provided comments pertaining to promoting natural gas as a clean alternative to 

coal in the Clean Power Plan. Commenters stated that by not including limits on methane 

emissions as well, the EPA is diluting its efforts to reduce global warming. Commenters noted

methane is more potent greenhouse gas than carbon. Commenters stated that when total lifecycle 

methane emissions from fracked natural gas are included, burning natural gas is equivalent to 

burning coal in terms of global warming. Commenters stated the EPA has underestimated 

methane emissions significantly. Commenters stated methane, like carbon, is a greenhouse 

gas. Commenters indicated it is a more potent greenhouse gas than carbon, 100 percent more 

potent because of the way it works in the atmosphere over a 20-year period. Commenters stated 

fracking for natural gas results in releasing unburned methane at all stages of the fracking 

process. Commenters stated that experts tell them that if total methane emissions throughout the 
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lifecycle of fracked natural gas reached three percent and has a fuel that is equal to burning coal 

in terms of global warming. Commenters indicated the most conservative average for methane 

released during the lifecycle of fracking is 5 percent to 7 percent, well above the 3 percent. 

Commenters stated the EPA's own study entitled "Improvements needed and EPA Efforts to 

Address Methane Emissions from Natural Gas Distribution Pipelines," issued on July 25, 2014, 

cautions that methane emissions from pipelines have been grossly underestimated. Commenters

noted a study entitled "Methane Leakage from North American Natural Gas Systems," published 

in the February 14, 2014, issue of the Journal of Science synthesizes diverse findings for more 

than 200 studies ranging in scope from local gas processing plants to total emissions from the US 

and Canada. Commenters quoted the article, "People who go out and actually measure methane 

pretty consistently find more emissions than we expect," says the lead author, Adam Brandt. 

Commenters also quoted, "Atmospheric tests covering the entire country indicating emissions 

around 50 percent more than the EPA estimates," said Brandt, and that is a moderate 

estimate. Commenters stated the EPA estimates are based on voluntary reporting of methane 

emissions from the natural gas industry.

Commenters stated that it is important that the EPA include the release of all greenhouse gas 

emissions, not just carbon dioxide in its regulations. Commenters stated methane gas, released by 

high-volume horizontal hydro-fracking is 80 times more potent a greenhouse gas than carbon 

dioxide in the first 20 years of its release to the atmosphere. Commenters stated NASA scientists 

have found that methane may actually have as much as 105 times more potency than CO2 in the 

same period. Commenters stated the EPA, however, has been using a much shorter 100-year 

time frame and, thereby, calculates the effect of methane as only 20 to 25 times more potent than 

carbon dioxide. Commenters stated due to the potency of methane, any leakage of the gas of 

more than two percent makes it a more dangerous greenhouse gas than carbon dioxide.

Commenters stated studies by NOAA of methane leakage from high-volume horizontal drilling 

for gas in the western U.S. shows annual leakage of between 2.3 percent and 17 percent from 

drilling and venting along pipelines, compressor stations, and storage facilities. Commenters

indicated the fracking industry itself admits that some 5 to 7 percent of its high volume wells 

leak in the first year of their drilling, and that after 30 years, up to 35 percent of its wells leak 

methane. Commenters stated that a recent study from the magazine Science, finds that the EPA 

has seriously underestimated the release of methane from fracking. Commenters indicated 

that to define methane gas obtained from high-volume, high-pressure hydro-fracked wells as 

clean energy is erroneous.

Commenters cited a study by Robert W. Howarth entitled "A Bridge to Nowhere: Methane 

Emissions and the Greenhouse Gas Footprint of Natural Gas" published in Energy Science & 

Engineering in April 2014 (available at 

http://onlinelibrary.wiley.com/doi/10.1002/ese3.35/pdf). Commenters stated that measurements 

by the NOAA and several other independent analyses indicate that at least 3 percent and 

potentially more than 7 percent of methane from natural gas is lost to the atmosphere prior to 

burning - far exceeding EPA estimates. Commenters stated that based on the most recent IPCC 

20-year GWP for methane, a leakage rate of 2.8 percent or higher actually causes natural gas to 

be more damaging than coal as a driver of climate change.

Commenters cited a study by Robert Howers, et al, from 2011 that concluded fugitive emissions 

and production losses of methane from natural gas fractured rock production practices have a 
85

higher climate change impact than coal-fired combustion. Commenters stated that the EPA has 

ignored this study and other studies that reached similar conclusions. Commenters stated that the 

problem with looking at the 100-year time period instead of the 20-year time period was summed 

up in an article by Joe Ron aptly titled, By the Time Natural Gas has a Net Climate Benefit, You 

Will Likely Be Dead and the Climate Ruined. 

Commenters stated that a full review of available data indicates that the level of emission 

reductions achievable by the proposed federal guideline may be negated by the greenhouse gas 

impacts of expanding natural gas production and associated venting. Commenters stated that the 

final rule should include accurate calculations of the expected increases in GHG emissions from 

the natural gas sector from implementing building block 2) corrected for the GWP of methane 

over a period of 10 years to ensure the switch from coal to natural gas will have the intended 

effect on climate change. Commenters also stated that the leak rates assumed in the proposal for 

natural gas systems are incorrect based on atmospheric measurements taken by NOAA in 2012. 

Commenters stated that the measurements by NOAA indicated leak rates ranged from 4 to 18 

percent in various regions compared to the 2.5 percent leak rate used for proposal. Commenters

also referenced a series of articles by two Cornell professors, Dr. Tony Agrafia and Dr. Robert 

Howorth that corroborated the leak rates published by NOAA. 

Commenters stated that only EGUs that can show they burn natural gas that is supplied by 

production, transmission, and distribution systems with a leak rate of less than half a percent 

should be allowed to displace coal units under building block 2. Commenters stated that the 

Environmental Defense Fund and the University of Texas have shown that a leak rate of less 

than half a percent is achievable when natural gas systems are properly operated.

Commenters supported the use of building block 1 in the proposal and stated that greater 

reductions of carbon emissions at coal plants are available if power plants simply match the 

lowest emission rate actually achieved by the plant over the past decade. 

Commenters stated total lifecycle emissions from methane gas-fired plants must be addressed. 

Commenters said, methane is a greenhouse gas even more potent than carbon. Commenters said, 

the rule does not address total lifecycle emissions from methane gas-fired plants, including 

leakage during production, processing and transmission, emissions flaring at gas wells, and 

energy consumed in production and transport of liquefied natural gas. Commenters said, 

researchers found methane leak rates of 100 to 1,000 times greater than the EPA estimates at 

well pads in Pennsylvania, and the EPA's office of the Inspector General just issued a report 

citing the Agency's failures to manage methane leaks from pipelines.

Commenters stated that while natural gas is seen as a bridge fuel by the Obama administration, 

in a State horribly wrecked by hydraulic fracturing, Pennsylvanians know it is not the answer.

Commenters stated methane escapes from natural gas drilling have a significantly greater global 

warming in the short term than carbon dioxide, according to NASA.

Commenters stated, if the goal is to reduce greenhouse gas emissions, then the expected increase 

in emissions of methane associated with production, transmission, and burning of fracked gas 

must be fully accounted for.
86

Commenters called upon the EPA to properly calculate the greenhouse effect of methane gas 

over a reasonable timeline, as well as to measure the release of methane from the high-volume 

horizontal drilling technology. Commenters indicated this will permit the establishment of CO2 

equivalents for released methane and to accurately calculate the greenhouse gas effects of 

fracked methane. Commenters stated proper steps must then be taken to control methane release 

and, if necessary, actually to ban high-volume hydro-fracking.

Commenters, graduate students, urged the EPA to impose an immediate moratorium on 

additional drilling for oil and natural gas in Colorado because their colleagues at the university 

have empirical evidence that methane emissions are 60 percent higher than assumed for the 

proposal. Commenters believed the moratorium should stay in place until we have the science 

that proves beyond a doubt that it is safe.

Commenters stated a range of studies have shown high level of methane leaks from gas drilling 

and fracking operations, undermining the notion that natural gas is a climate solution or a 

transition fuel. Commenters noted that major studies have concluded that early work by the EPA 

greatly underestimated the impacts of methane and natural gas drilling on the climate.

Commenters stated that the EPA's estimate for methane contribution to climate change is too 

low. Commenters indicated the EPA has significantly underestimated emission rates of methane 

from active gas fields, and has underestimated the warming potential of methane. Commenters

noted the EPA must account for increases in the amount of methane emissions from gas-fired 

power plants which result from coal-fired power plants converting the gas or from new gaspowered plants. Commenters stated the EPA's estimates for methane contribution to climate 

change still lag far behind scientific consensus, which deemphasizes the impact that the natural 

gas sector will have on climate change. Commenters stated a recent study published in 

the National Academy of Sciences found that emissions rates of methane from active gas fields 

were 1,000 times higher than EPA estimates. Commenters stated the IPCC recently reported that 

methane is 86 times more potent at warming our planet than carbon over a 20-year time period, 

while research by a NASA scientist shows that methane is 105 times more potent when including 

aerosol effects. Commenters noted the EPA's global warming potential of 25 is inadequate for 

studying regulations. Commenters indicated the lifecycle emissions from the gas industry may 

already be worse for the climate than coal. Commenters stated methane emissions will increase if 

plants switch to natural gas when methane emissions from active gas fields are considered.

Commenters stated the EPA should also set methane emission reduction targets for oil and gas 

industry. Commenters stated that in addition, the EPA must move quickly on setting ambitious 

methane reduction targets or regulations for the oil and gas industry.

Commenters stated that the EPA has to step up and directly regulate methane, both from oil and 

gas and coproducing wells, during gas production, during gas processing, and during transport on 

new and existing wells.

Commenters stated that the Clean Power Plan will not solve climate change in isolation.

Commenters indicated that as a nation, we will have to tackle methane leaks from oil and gas.
87

Commenters stated, if you know anything about fracking, the government has given their state 

[PA] over as a sacrifice zone to the natural gas industry, and commenters hoped at some point 

[EPA] will also regulate methane, which is a much more powerful gas than CO2.

Commenters stated, one-hundred miles away they are developing an oil field at an amazing pace 

in the Bakken Region of North Dakota and Montana. Commenters indicated there is natural gas 

that is a by-product and is simply being flared and wasted. Commenters stated we should salvage 

all the natural gas now being wasted. Commenters stated methane emissions are a greenhouse 

gas that must be looked at in addition to carbon dioxide. Commenters indicated it is critical that 

the BLM's proposal to limit flaring and venting of methane and the EPA's methane pollution 

standards move forward. Commenters noted that otherwise, switching from coal to natural gas 

could make climate change worse, not better. Commenters stated even with better controls on 

methane, though, promoting natural gas is not a good solution to climate change; energy 

efficiency and renewable energy are much better.

Commenters stated that EPA should account for carbon dioxide equivalents, not just CO2 in 

order to encompass other greenhouse gases that are emitted from the extraction, storage, 

transport and generation components of fuel combustion. Commenters cited, as an example, 

methane emissions that can be released during natural gas extraction and transport.

Commenters urged the EPA to act quickly to release meaningful standards for methane, 

particularly extraction of methane.

Commenters stated that without including limits on methane emissions, the EPA will be leaving 

out a massively important source of greenhouse gas emissions. Commenters noted that other 

witnesses have testified that methane has a severe impact on greenhouse gas versus carbon 

dioxide on the 20-year term. Commenters thought methane leakage, especially at the point of 

extraction is a major concern.

Commenters stated the International Energy Agency tells us that two-thirds of proven fossil fuel 

reserves must be kept in the ground to prevent potential catastrophic consequences. Commenters

noted this includes natural gas and oil. Commenters stated about one-third of the total U.S. 

methane emissions are responsible for greenhouse gas emissions [sic]. Commenters added the 

new unconventional gas wells are also emitting toxins like benzene, and radon that are then sent 

through compressor stations and pipelines. Commenters stated that several studies have shown 

that overall, methane emissions are considerably higher than official inventories report.

Commenters stated that without sensible health based regulations for the unconventional, natural 

gas industry, the economic and health benefits of the proposed rule will be undone and create 

potentially equally daunting challenges for future Pennsylvanians. Commenters indicated the 

EPA and Pennsylvania DEP should (1) require best available technology for capturing 

unintended methane emissions, green completions and close wastewater systems; (2) create 

systems and enforcement from monitoring of well bore integrity; (3) weigh out health protective, 

well permitting guidelines; (4) enforcement authority and resources for state and local agencies 

to oversee this emerging industry; (5) transparency around reduced water components and 

disposal systems; and (6) a prospective epidemiological investigation of potential health effects 

which are to date unknown and under investigated.
88

Commenters believed that replacing coal with natural gas is not a valid solution to climate 

change and the only long-term solution is for the U.S. to rapidly develop renewable energy 

systems that will quickly free us from dependence on all fossil fuels. Commenters believed this 

approach makes both environmental and economic sense. Commenters believed the final rule 

should reflect the potential for using renewables. Commenters opposed regulating methane 

losses in a later federal regulatory action (separate from the current 111(d) action) because the 

proposed 111(d) rule could lead states to ignore the potential climate benefits of renewables and 

to make decisions about long-term investments in electricity generation based only on 

combustion emissions. Commenters believed states may make poor choices in their 111(d) plans 

if they are not presented with all the facts about methane losses. Commenters noted that the 

proposal's Regulatory Impact Analysis (RIA) indicated the rule would boost the amount of 

additional electricity generation from natural gas by nearly ten times the gain projected for 

renewables before 2020. Commenters believed that by accelerating EGU investments in natural 

gas in the near-term, the plan could tip the scales toward fossil fuels for decades to come, and 

commenters believed that once gas-fired plants are in operation, there will be less incentive for 

utilities to reinvest in renewables because the capital outlay for gas infrastructure will have 

already occurred.

Commenters requested that the EPA protect us against harmful methane and fracking.

Commenters stated natural gas is not the answer; clean, renewable energy is the answer.

Commenters stated that the nation needs to dedicate substantial resources to the research and 

development of technology to store energy generated from wind and solar on a large scale in 

order to move past the fossil fuel age.

Comment 8: Innovative projects for converting methane to electricity.

Response 8: EPA does not agree the BSER should include measures that reduce non-carbon 

dioxide greenhouse gas emissions. BSER measures reflect those strategies and measures that 

reduce emissions at the affected source. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the final rule should be more flexible and allow the use of technologies 

to reduce other greenhouse gas emissions that are more potent than CO2. Commenters believed

the use of a carbon dioxide equivalent should be allowed in the development of the state plans 

such as allowing programs for controlling fugitive methane emissions from landfills and 

confinement feeding operations, then using the captured methane to produce electricity.

Commenters, state air quality permitting authorities, stated that the proposed federal guideline 

hinders technological innovation by not providing adequate flexibility, credit, or incentives for. 

Commenters stated that under the New Source Performance Standard and Emission Guidelines 

programs, the EPA must establish emission standards (consistent with the definition under 

section 111(a)(1) based on the Best System of Emission Reduction and must consider whether 

such a standard promotes the development of technology (consistent with Sierra Club v. Costle 
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(D.C. Cir. 1981)). Commenters stated that the proposed federal guidelines do not allow states to 

take credit for non-carbon dioxide greenhouse gas emission reductions, making it more difficult 

for states to invest in new emission control technologies and stifling technological innovation. 

Commenters requested that the final rule allow state 111(d) plans to take credit for non-carbon 

dioxide greenhouse gas emission reductions that reduce electricity demand. Commenters

provided the following example: collection of methane from landfill gas and livestock operations 

for use in combustion engines to generate electricity. Commenters stated that Nebraska's 

potential for methane capture is vast because the state had 6.4 million cattle and 3 million hogs in 

2012, ranking 2nd and 6th in the nation, respectively. Commenters stated that Nebraska currently 

has one methane capture and combustion system at a livestock operation which provides 80 

kilowatts of installed electricity capacity and reduces methane emissions by 107 metric tons/year 

(2,228 metric tons carbon dioxide-equivalent per year). Commenters stated that utilities and 

livestock operations in Nebraska have expressed interest in deploying additional methane capture 

and combustion systems, but cannot justify their high capital costs without adequate credit for 

GHG emission reductions under the Clean Power Plan. Commenters stated that since the globalwarming potential of methane and other non-carbon dioxide greenhouse gasses is many times 

greater than carbon dioxide, allowing states to take credit for reducing these emissions would 

increase flexibility in state plans, reduce the burden on regulated sources, and bolster the 

emission reduction goals of EPA's Clean Power Plan. Commenters requested that the final 

federal guideline allow these types of innovative projects as compliance options in state plans.

Comment 9: Supply chain LNG projects

Response 9: As explained in section VIII of the preamble, the EPA is not finalizing the proposed 

portfolio approach and any comments on that proposed approach to 111(d) state plan design are 

therefore moot. Instead, the EPA is finalizing an option to submit a “state measures” plan type, 

under which a mass CO2 emission goal may be partially or entirely achieved through state 

measures that impose requirements on entities other than affected EGUs that are not included in 

the federally enforceable 111(d) state plan, provided the state submits standards of performance 

for CO2 emissions from affected EGUs in the form of a federally enforceable “backstop” that 

would be triggered if the state measures fail to achieve the required CO2 emission performance 

level. Under a state measures plan, the backstop emission standards constitute the standards of 

performance required by section 111(d), and the state plan provides for the implementation and 

enforcement of such standards of performance by specifying the trigger mechanism and 

conditions under which the backstop emission standards apply to affected EGUs. Upon EPA 

approval of a state measures plan under section 111(d), the backstop emission standards become 

federally enforceable requirements, which EPA and citizens may enforce against affected EGUs 

under section 113 and section 304.

The following are summaries of the specific public comments under this comment:

Commenters noted that there are a number of concurrent, ongoing efforts to bring natural gas to 

Fairbanks that may be compromised by the application of the CPP rule. As an example, 

commenters noted that the State of Alaska is investing approximately $350 million dollars 

through the Interior Energy Project to bring liquefied natural gas (LNG) into Fairbanks by 2016. 
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Commenters stated the work on this "supply chain" project includes construction of a North 

Slope LNG plant, securing long range transport contracts, increasing community LNG storage 

capacity, expanding the existing limited natural gas distribution system in Fairbanks and starting 

a new distribution utility in the outlying area. Commenters noted that an important aspect of this 

effort would be engaging potential large anchor consumers of natural gas to purchase the LNG 

from this project. Commenters stated that converting from liquid fuels to cost-effective natural 

gas for local electrical generation would help to solidify the economics of the natural gas project, 

thus helping to ensure that cleaner burning fuel would also be available for distribution for space 

heating through a local utility. Commenters noted that delivering natural gas to Fairbanks and 

converting electric generation from liquid fuels would also reduce carbon emissions. 

However, commenters noted that these extraordinary efforts would not qualify for inclusion in 

any state plan under this proposed rule. First, commenters noted that these projects are not 

measures that could be "enforceable" or that should be subject to citizen suits. Second, 

commenters noted that many of the generators that may be affected by the arrival of natural gas 

in Fairbanks are diesel or naphtha units not covered by the rule. Third, to the extent these efforts 

focus on space heating, commenters noted that those measures would not reduce emissions at 

"affected EGUs" and would not be credited to the state.

Commenters argued that, as with the retirement of the Healy coal units, disrupting Alaska's plans 

to bring natural gas to Fairbanks may have the irrational result of contributing to air quality 

problems. Commenters stated a portion of the Fairbanks North Star Borough, including the cities 

of Fairbanks and North Pole, is designated as a fine particulate matter nonattainment area.

Commenters noted that space heating from wood, coal, and fuel oil all contribute to the issue. 

Commenters stated one of the challenges in reducing PM2.5 air pollution in these communities is 

a lack of available, affordable, cleaner-burning natural gas in the community. Commenters noted 

that the increasing cost of electricity in this region has contributed to a significant increase in the 

use of wood burning stoves for space heating, increasing both particulate and carbon emissions 

as residents try desperately to lower their overall monthly energy costs. Commenters argued that 

EPA's proposed rule would only further increase energy costs. By contrast, commenters noted 

that projects already being assessed in Alaska could have substantial benefits to the state and 

national economy while simultaneously reducing carbon emissions.

Comment 10: Include natural gas-fired reciprocating internal combustion engines under the final 

rule.

Response 10: The EPA did not propose to include reciprocating internal combustion engines in 

the rule. In addition the majority of reciprocating internal combustion engines are smaller than 

25 MW and would not be covered by the rule. 

The following are summaries of the specific public comments under this comment:

Commenters, air quality permitting authorities, recommended that the final federal guidelines 

should alter the proposed applicability criteria to allow states the option to include natural gas-
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fired reciprocating internal combustion engines (RICE) in their state plans because this 

permitting authority has recently permitted several electric generating facilities (each with 

approximately 100 MW capacity) that are powered by sets of natural gas-fired RICE. 

Commenters stated that the estimated CO2 emission rate for these EGUs is less than 1,100 

lbs/MWh which is significantly lower than the nominal goal of 1,499 lbs/MWh proposed for the 

State of Kansas in the year 2030. Commenters also recommended that states opting to include 

natural gas-fired RICE in their state plans should be exempted from the requirement to install 

CO2 CEMS and that the final rule allow these sources to monitor CO2 emissions based on an 

approved mass balance.